EnLink Midstream (ENLC) 10-Q 5 Aug 20 2020 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2020	Jul. 30, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
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
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)		489,593,387
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2020
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 52	$ 77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	82	36.2
Accrued revenue and other	304.7	460.1
Fair value of derivative assets	9.9	12.9
Other current assets	58.6	57.8
Total current assets	507.2	644.4
Property and equipment, net of accumulated depreciation of $3,654.7 and $3,418.6, respectively	6,828.7	7,081.3
Intangible assets, net of accumulated amortization of $607.1 and $545.9, respectively	1,187.1	1,249.9
Goodwill	0	184.6
Investment in unconsolidated affiliates	42.1	43.1
Fair value of derivative assets	5.8	4.3
Other assets, net	147.9	128.2
Total assets	8,718.8	9,335.8
Current liabilities:
Accounts payable and drafts payable	49.4	70.6
Accounts payable to related party	0.4	1.1
Accrued gas, NGLs, condensate, and crude oil purchases	188.8	354.8
Fair value of derivative liabilities	31.3	14.4
Other current liabilities	160.2	206.2
Total current liabilities	430.1	647.1
Long-term debt	4,749	4,764.3
Asset retirement obligations	15.9	15.5
Other long-term liabilities	84.8	90.8
Fair value of derivative liabilities	9.4	6.8
Redeemable non-controlling interest	0	5.2
Members’ equity:
Members’ equity (489,463,987 and 487,791,612 units issued and outstanding, respectively)	1,728.5	2,135.5
Accumulated other comprehensive loss	(22.6)	(11)
Non-controlling interest	1,723.7	1,681.6
Total members’ equity	3,429.6	3,806.1
Total liabilities and members’ equity	$ 8,718.8	$ 9,335.8

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
ASSETS
Allowance for bad debt	$ 0.5	$ 0.5
Property and equipment, accumulated depreciation	3,654.7	3,418.6
Intangible assets, accumulated amortization	$ 607.1	$ 545.9
Members’ equity:
Common units issued (in shares)	489,463,987	487,791,612
Common units outstanding (in shares)	487,791,612	489,463,987

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Revenues:
Revenue from contracts with customers	$ 767.3	$ 1,703.1	$ 1,904.2	$ 3,480.5
Gain (loss) on derivative activity	(22.4)	6.9	(3.2)	8.7
Total revenues	744.9	1,710	1,901	3,489.2
Operating costs and expenses:
Cost of sales	397.7	1,300.1	1,153	2,663.5
Operating expenses	88.1	117.9	188.8	232.4
General and administrative	23.5	32.2	53.9	83.6
Loss on disposition of assets	5.2	0.1	4.6	0.1
Depreciation and amortization	158.2	153.7	321	305.8
Impairments	1.5	0	354.5	186.5
Loss on secured term loan receivable	0	52.9	0	52.9
Total operating costs and expenses	674.2	1,656.9	2,075.8	3,524.8
Operating income (loss)	70.7	53.1	(174.8)	(35.6)
Other income (expense):
Interest expense, net of interest income	(55.2)	(54.3)	(110.8)	(103.9)
Gain on extinguishment of debt	26.7	0	32	0
Income (loss) from unconsolidated affiliates	(0.7)	4.7	1	10
Other income	0	0.2	0	0.2
Total other expense	(29.2)	(49.4)	(77.8)	(93.7)
Income (loss) before non-controlling interest and income taxes	41.5	3.7	(252.6)	(129.3)
Income tax benefit (expense)	(11.7)	5.4	22	3.6
Net income (loss)	29.8	9.1	(230.6)	(125.7)
Net income attributable to non-controlling interest	25.7	25.2	52.1	66.7
Net income (loss) attributable to ENLC	$ 4.1	$ (16.1)	$ (282.7)	$ (192.4)
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ 0.01	$ (0.03)	$ (0.58)	$ (0.44)
Diluted common unit (in dollars per share)	$ 0.01	$ (0.03)	$ (0.58)	$ (0.44)
Product sales
Revenues:
Revenue from contracts with customers	$ 532.6	$ 1,450.4	$ 1,425.5	$ 2,981.3
Midstream services
Revenues:
Revenue from contracts with customers	$ 234.7	$ 252.7	$ 478.7	$ 499.2

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2020		Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 29.8		$ 9.1	$ (230.6)	$ (125.7)
Gain (loss) on designated cash flow hedge	[1]	1.5		(9.9)	(11.6)	(9.9)
Comprehensive income (loss)		31.3		(0.8)	(242.2)	(135.6)
Comprehensive income attributable to non-controlling interest		25.7		25.2	52.1	66.7
Comprehensive income (loss) attributable to ENLC		5.6		(26)	(294.3)	(202.3)
Income tax (benefit)		$ 0.5	[1]	$ (3.6)	$ (3.5)	$ (3.6)
[1]	Includes a tax expense of $0.5 million and a tax benefit of $3.5 million for the three and six months ended June 30, 2020, respectively, and a tax benefit of $3.6 million for the three and six months ended June 30, 2019, respectively.

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Cumulative Effect, Period of Adoption, Adjustment	Cumulative Effect, Period of Adoption, Adjusted Balance	Redeemable Non-Controlling Interest (Temporary Equity)	Common Units	Common UnitsCumulative Effect, Period of Adoption, Adjustment	Common UnitsCumulative Effect, Period of Adoption, Adjusted Balance	Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive LossCumulative Effect, Period of Adoption, Adjusted Balance	Non-Controlling Interest	Non-Controlling InterestCumulative Effect, Period of Adoption, Adjusted Balance	Redeemable Non-Controlling Interest (Temporary Equity)	Redeemable Non-Controlling Interest (Temporary Equity)Cumulative Effect, Period of Adoption, Adjusted Balance
Member equity, beginning balance at Dec. 31, 2018		$ 4,974.2		$ 0.3	$ 4,974.5		$ 1,730.9	$ 0.3	$ 1,731.2	$ (2)	$ (2)	$ 3,245.3	$ 3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018							181,300,000		181,300,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(8.4)					$ (5.6)					(2.8)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)							1,000,000
Unit-based compensation		13.6					$ 12.2					1.4
Contributions from non-controlling interests		15.7										15.7
Distributions		(178.6)					(51)					(127.6)
Fair value adjustment related to redeemable non-controlling interest		2.5					2.5							$ (2.1)
Net income (loss)		(134.8)					(176.3)					41.5		0
Issuance of common units for ENLK public common units related to the Merger		399					$ 1,958.1					(1,559.1)
Issuance of common units for ENLK public common units related to the Merger (in shares)							304,900,000
Member equity, end balance at Mar. 31, 2019		5,083.5					$ 3,471.1			(2)		1,614.4
Units outstanding, end balance (in shares) at Mar. 31, 2019							487,200,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018														9.3	$ 9.3
Increase (Decrease) in Temporary Equity
Distributions		(178.6)					$ (51)					(127.6)
Fair value adjustment related to redeemable non-controlling interest		2.5					2.5							(2.1)
Redeemable noncontrolling interest, ending balance at Mar. 31, 2019														7.2
Member equity, beginning balance at Dec. 31, 2018		4,974.2		$ 0.3	$ 4,974.5		$ 1,730.9	$ 0.3	$ 1,731.2	(2)	$ (2)	3,245.3	$ 3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018							181,300,000		181,300,000
Increase (Decrease) in Members' Equity
Gain (loss) on designated cash flow hedge	[1]	(9.9)
Member equity, end balance at Jun. 30, 2019		4,946.7					$ 3,324.6			(11.9)		1,634
Units outstanding, end balance (in shares) at Jun. 30, 2019							487,200,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018														9.3	$ 9.3
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest		0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2019														5.8
Member equity, beginning balance at Mar. 31, 2019		5,083.5					$ 3,471.1			(2)		1,614.4
Units outstanding, beginning balance (in shares) at Mar. 31, 2019							487,200,000
Increase (Decrease) in Members' Equity
Unit-based compensation		6.6					$ 6.6					0
Contributions from non-controlling interests		29.5										29.5
Distributions		(172.3)					(137.2)					(35.1)
Fair value adjustment related to redeemable non-controlling interest		0.2					0.2					0		(1.4)
Gain (loss) on designated cash flow hedge		(9.9)	[1]							(9.9)
Net income (loss)		9.1					(16.1)					25.2		0
Member equity, end balance at Jun. 30, 2019		4,946.7					$ 3,324.6			(11.9)		1,634
Units outstanding, end balance (in shares) at Jun. 30, 2019							487,200,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2019														7.2
Increase (Decrease) in Temporary Equity
Distributions		(172.3)					$ (137.2)					(35.1)
Fair value adjustment related to redeemable non-controlling interest		0.2					0.2					0		(1.4)
Redeemable noncontrolling interest, ending balance at Jun. 30, 2019														5.8
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		487,791,612					487,800,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		$ (4)					$ (4)
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
Contributions from non-controlling interests		37.1										37.1
Distributions		(117.7)					(93.3)					(24.4)		(0.3)
Fair value adjustment related to redeemable non-controlling interest		0.7					0.7							(0.9)
Gain (loss) on designated cash flow hedge	[1]	(13.1)								(13.1)
Net income (loss)		(260.4)					(286.8)					26.4
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)
Redemption of non-controlling interest						$ (4)
Fair value adjustment related to redeemable non-controlling interest		0.7					0.7							(0.9)
Redeemable noncontrolling interest, ending balance at Mar. 31, 2020														0
Member equity, beginning balance at Dec. 31, 2019		$ 3,806.1					$ 2,135.5			(11)		1,681.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2019		487,791,612					487,800,000
Increase (Decrease) in Members' Equity
Gain (loss) on designated cash flow hedge	[1]	$ (11.6)
Member equity, end balance at Jun. 30, 2020		$ 3,429.6					$ 1,728.5			(22.6)		1,723.7
Units outstanding, end balance (in shares) at Jun. 30, 2020		489,463,987					489,500,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2019														5.2
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest		$ 4				$ (4)
Redeemable noncontrolling interest, ending balance at Jun. 30, 2020														0
Member equity, beginning balance at Mar. 31, 2020		3,461					$ 1,764.4			(24.1)		1,720.7
Units outstanding, beginning balance (in shares) at Mar. 31, 2020							489,100,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.3)					$ (0.3)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)							400,000
Unit-based compensation		6.8					$ 6.8
Contributions from non-controlling interests		13.2										13.2
Distributions		(82.4)					(46.5)					(35.9)		0
Gain (loss) on designated cash flow hedge		1.5	[1]							1.5
Net income (loss)		29.8					4.1					25.7
Member equity, end balance at Jun. 30, 2020		$ 3,429.6					$ 1,728.5			$ (22.6)		1,723.7
Units outstanding, end balance (in shares) at Jun. 30, 2020		489,463,987					489,500,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2020														0
Increase (Decrease) in Temporary Equity
Distributions		$ (82.4)					$ (46.5)					$ (35.9)		0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2020														$ 0
[1]	Includes a tax expense of $0.5 million and a tax benefit of $3.5 million for the three and six months ended June 30, 2020, respectively, and a tax benefit of $3.6 million for the three and six months ended June 30, 2019, respectively.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2020		Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Statement of Stockholders' Equity [Abstract]
Income tax (benefit)	$ 0.5	[1]	$ (4)	$ (3.6)	$ (3.5)	$ (3.6)
[1]	Includes a tax expense of $0.5 million and a tax benefit of $3.5 million for the three and six months ended June 30, 2020, respectively, and a tax benefit of $3.6 million for the three and six months ended June 30, 2019, respectively.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities:
Net loss	$ 29.8	$ 9.1	$ (230.6)	$ (125.7)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairments	1.5	0	354.5	186.5
Depreciation and amortization	158.2	153.7	321	305.8
Loss on secured term loan receivable	0	52.9	0	52.9
Deferred income tax benefit	11.3	(5.7)	(22.7)	(4.9)
Non-cash unit-based compensation			16.2	19.1
(Gain) loss on derivatives recognized in net loss	22.4	(6.9)	3.2	(8.7)
Cash settlements on derivatives			2.8	4.9
Gain on extinguishment of debt	(26.7)	0	(32)	0
Amortization of debt issue costs, net discount (premium) of notes			2.2	2.9
Distribution of earnings from unconsolidated affiliates			1.2	9.7
Income from unconsolidated affiliates	0.7	(4.7)	(1)	(10)
Other operating activities			4.1	(3)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other			109.8	270.7
Natural gas and NGLs inventory, prepaid expenses, and other			9.3	(7.4)
Accounts payable, accrued product purchases, and other accrued liabilities			(221.2)	(171.3)
Net cash provided by operating activities			316.8	521.5
Cash flows from investing activities:
Additions to property and equipment			(203.6)	(428.4)
Other investing activities			1.6	1.5
Net cash used in investing activities			(202)	(426.9)
Cash flows from financing activities:
Proceeds from borrowings			490	2,320
Payments on borrowings			(476)	(2,131.4)
Debt financing costs			0	(9.7)
Conversion of restricted units, net of units withheld for taxes			(4.3)	(8.4)
Distribution to members			(139.8)	(188.2)
Distributions to non-controlling interests			(60.6)	(162.7)
Contributions by non-controlling interests			50.3	45.2
Other financing activities			0.2	(0.8)
Net cash used in financing activities			(140.2)	(136)
Net decrease in cash and cash equivalents			(25.4)	(41.4)
Cash and cash equivalents, beginning of period			77.4	100.4
Cash and cash equivalents, end of period	$ 52	$ 59	52	59
Supplemental disclosures of cash flow information:
Cash paid for interest			106.6	103.7
Cash paid (refunded) for income taxes			(1)	1.2
Non-cash investing activities:
Non-cash accrual of property and equipment			(19.6)	(5.8)
Right-of-use assets obtained in exchange for operating lease liabilities			4.8	95.2
Redemption of non-controlling interest			$ (4)	$ 0

General

General	6 Months Ended
	Jun. 30, 2020
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. 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 the common units of ENLK, a Delaware limited partnership formed in 2002. EnLink Midstream GP, LLC, a Delaware limited liability company and our wholly-owned subsidiary, is ENLK’s 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 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. Current Market Environment On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has now reached every region of the globe and has resulted in widespread adverse impacts on the global economy, on the energy industry as a whole and on midstream companies, and on our customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a reduction in global demand for condensate, natural gas, and NGLs and especially crude oil. While reductions in global demand for natural gas and NGLs were never as severe as for crude oil and the demand for crude oil has recovered from the steepest drops in April and May, global demand for energy is still reduced as of the date of this report from levels before the pandemic in mid-February. The decline in demand, coupled with the failure of OPEC+ to quickly agree on oil production cuts, resulted in a decline in the market price for these commodities, most severely for crude oil. Although OPEC+ agreed to production cuts in April, extended these cuts through July, and are expected to continue the production cuts beyond July, although at a more moderate level, and although United States oil producers have also curtailed their drilling programs, these cuts have not been enough to fully offset demand loss attributable to the COVID-19 pandemic and market prices remain lower than prior to the pandemic. As a result of the supply/demand imbalance, reduced commodity prices, and an uncertain timeline for recovery, oil and natural gas producers, including many of our customers, have curtailed their current drilling and production activity, including in some cases by shutting-in production, as well as reducing their plans for future drilling and production activity. As a result of these decreases in producer activity, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 2020
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, 2019. 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 Minimum Volume Commitments and Firm Transportation Contracts 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 and six months ended June 30, 2020, we had contractual commitments of $41.4 million and $83.2 million under our MVC contracts, respectively, and recorded $13.4 million and $25.2 million of revenue due to volume shortfalls, respectively. MVC and Firm Transportation Commitments (in millions) (1) 2020 (remaining) $ 126.9 2021 115.1 2022 99.8 2023 90.5 2024 77.0 Thereafter 143.3 Total $ 652.6 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. c. Property and Equipment Impairment Review. In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. For the three months ended June 30, 2020, we recognized a $1.5 million impairment on property and equipment related to cancelled projects. For the six months ended June 30, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and a $1.9 million impairment related to certain cancelled projects. d. Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interests are not considered to be a component of members’ equity and are reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as a redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets. During the first quarter of 2020, a non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated liability of $4.0 million related to the redemption of the non-controlling interest on the consolidated balance sheet as of June 30, 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder. e. Adopted Accounting Standards Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three and six months ended June 30, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.” Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	6 Months Ended
	Jun. 30, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	(3) Goodwill and Intangible Assets Goodwill We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year cash flow multiples, and estimated future cash flows, including volume and price forecasts, capital expenditures, and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. Goodwill Impairment Analysis for the six months ended June 30, 2020 During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $184.6 million was recognized as an impairment loss on the consolidated statement of operations for the six months ended June 30, 2020. Goodwill Impairment Analysis for the six months ended June 30, 2019 During the first quarter of 2019, we recognized a $186.5 million goodwill impairment in our Louisiana reporting unit. Intangible Assets The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2020 Customer relationships, beginning of period $ 1,795.8 $ (545.9) $ 1,249.9 Amortization expense — (61.8) (61.8) Retirements (1) (1.6) 0.6 (1.0) Customer relationships, end of period $ 1,794.2 $ (607.1) $ 1,187.1 ____________________________ (1) Intangible assets retired as a result of the disposition of certain non-core 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 weighted average amortization period is 15.0 years. Amortization expense was $30.9 million and $31.0 million for the three months ended June 30, 2020 and 2019, respectively, and $61.8 million and $61.9 million for the six months ended June 30, 2020 and 2019, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 (remaining) $ 61.7 2021 123.4 2022 123.4 2023 123.4 2024 123.4 Thereafter 631.8 Total $ 1,187.1

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2020
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions Transactions with Cedar Cove JV. For the three and six months ended June 30, 2020, we recorded cost of sales of $1.3 million and $4.2 million, respectively, and for the three and six months ended June 30, 2019, we recorded cost of sales of $5.8 million and $13.9 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at its Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $0.4 million and $1.1 million at June 30, 2020 and December 31, 2019, respectively.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2020
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of June 30, 2020 and December 31, 2019, long-term debt consisted of the following (in millions): June 30, 2020 December 31, 2019 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Consolidated Credit Facility due 2024 (1) $ 400.0 $ — $ 400.0 $ 350.0 $ — $ 350.0 Term Loan due 2021 (2) 850.0 — 850.0 850.0 — 850.0 ENLK’s 4.40% Senior unsecured notes due 2024 521.8 1.2 523.0 550.0 1.5 551.5 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.6) 720.2 750.0 (0.7) 749.3 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.4) 490.6 500.0 (0.5) 499.5 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 500.0 — 500.0 ENLK’s 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 ENLK’s 5.05% Senior unsecured notes due 2045 450.0 (5.8) 444.2 450.0 (5.9) 444.1 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,782.3 $ (5.9) 4,776.4 $ 4,800.0 $ (5.9) 4,794.1 Debt issuance cost (3) (27.4) (29.8) Long-term debt, net of unamortized issuance cost $ 4,749.0 $ 4,764.3 ____________________________ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.8% and 3.3% at June 30, 2020 and December 31, 2019, respectively. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.7% and 3.2% at June 30, 2020 and December 31, 2019, respectively. (3) Net of amortization of $12.6 million and $10.9 million at June 30, 2020 and December 31, 2019, respectively. 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 defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($400.0 million as of June 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($23.0 million as of June 30, 2020). The obligations under the Consolidated Credit Facility are unsecured. The Consolidated Credit Facility includes provisions for additional financial institutions to become lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $2.25 billion for all commitments under the Consolidated Credit Facility. The Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated Credit Facility contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately. At June 30, 2020, 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. 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 $850.0 million as of June 30, 2020. The obligations under the Term Loan are unsecured. The Term Loan will mature on December 10, 2021. The Term Loan contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Term Loan bear interest at ENLC’s option at LIBOR plus an applicable margin (ranging from 1.0% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.5%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately. At June 30, 2020, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan for at least the next twelve months. Senior Unsecured Notes Repurchases For the three and six months ended June 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions): Three Months Ended Six Months Ended Debt repurchased $ 57.2 $ 67.7 Aggregate payments (30.8) (36.0) Net discount on repurchased debt (0.3) (0.3) Accrued interest on repurchased debt 0.6 0.6 Gain on extinguishment of debt $ 26.7 $ 32.0

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2020
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 Six Months Ended 2020 2019 2020 2019 Current income tax expense $ (0.4) $ (0.3) $ (0.7) $ (1.3) Deferred income tax benefit (expense) (11.3) 5.7 22.7 4.9 Income tax benefit (expense) $ (11.7) $ 5.4 $ 22.0 $ 3.6 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 Six Months Ended 2020 2019 2020 2019 Expected income tax benefit (expense) based on federal statutory rate $ (3.7) $ 4.5 $ 63.6 $ 41.2 State income tax benefit (expense), net of federal benefit (1.0) 0.4 7.0 4.3 Unit-based compensation (1) (6.8) (0.1) (4.4) — Non-deductible expense related to goodwill impairment — — (43.4) (43.8) Other (0.2) 0.6 (0.8) 1.9 Income tax benefit (expense) $ (11.7) $ 5.4 $ 22.0 $ 3.6 ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of restricted incentive units. Deferred Tax Assets and Liabilities

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	6 Months Ended
	Jun. 30, 2020
Partners' Capital [Abstract]
Certain Provisions of the ENLK Partnership Agreement	(7) Certain Provisions of the ENLK Partnership Agreement a. Series B Preferred Units As of June 30, 2020 and December 31, 2019, there were 59,897,920 and 59,599,550 Series B Preferred Units issued and outstanding, respectively. A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2020 and 2019 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 Second Quarter of 2020 149,745 $ 16.8 August 13, 2020 2019 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019 Second Quarter of 2019 148,257 $ 17.1 August 13, 2019 b. Series C Preferred Units As of June 30, 2020 and December 31, 2019, there were 400,000 Series C Preferred Units issued and outstanding. ENLK distributed $12.0 million to holders of Series C Preferred Units during the three and six months ended June 30, 2020 and 2019, respectively. c. ENLK Common Unit Distributions

Members' Equity

Members' Equity	6 Months Ended
	Jun. 30, 2020
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 Six Months Ended 2020 2019 2020 2019 Distributed earnings allocated to: Common units (1) $ 45.9 $ 137.8 $ 91.7 $ 247.2 Unvested restricted units (1) 0.8 1.8 1.6 3.0 Total distributed earnings $ 46.7 $ 139.6 $ 93.3 $ 250.2 Undistributed loss allocated to: Common units $ (42.2) $ (153.5) $ (369.6) $ (437.3) Unvested restricted units (0.4) (2.2) (6.4) (5.3) Total undistributed loss $ (42.6) $ (155.7) $ (376.0) $ (442.6) Net income (loss) allocated to: Common units $ 3.7 $ (15.7) $ (277.9) $ (190.1) Unvested restricted units 0.4 (0.4) (4.8) (2.3) Total net income (loss) $ 4.1 $ (16.1) $ (282.7) $ (192.4) Basic and diluted net income (loss) per unit: Basic $ 0.01 $ (0.03) $ (0.58) $ (0.44) Diluted $ 0.01 $ (0.03) $ (0.58) $ (0.44) ____________________________ (1) For the three months ended June 30, 2020 and 2019, distributed earnings represent a declared distribution of $0.09375 per unit payable on August 13, 2020 and a distribution of $0.283 per unit paid on August 13, 2019, respectively. (2) For the six months ended June 30, 2020, distributed earnings included a distribution of $0.09375 per unit paid on May 13, 2020 and a declared distribution of $0.09375 per unit payable on August 13, 2020. For the six months ended June 30, 2019, distributed earnings included distributions of $0.279 per unit paid on May 14, 2019 and $0.283 per unit paid on August 13, 2019. The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Basic weighted average units outstanding: Weighted average common units outstanding 489.3 487.2 489.0 439.9 Diluted weighted average units outstanding: Weighted average basic common units outstanding 489.3 487.2 489.0 439.9 Dilutive effect of non-vested restricted units (1) 1.1 — — — Total weighted average diluted common units outstanding 490.4 487.2 489.0 439.9 ____________________________ (1) All common unit equivalents were antidilutive for the six months ended June 30, 2020 and for the three and six months ended June 30, 2019 since a net loss existed for those periods. b. Distributions A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2020 and 2019, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020 Second Quarter of 2020 $ 0.09375 August 13, 2020 2019 Fourth Quarter of 2018 $ 0.275 February 14, 2019 First Quarter of 2019 $ 0.279 May 14, 2019 Second Quarter of 2019 $ 0.283 August 13, 2019

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2020
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates As of June 30, 2020, 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 Six Months Ended 2020 2019 2020 2019 GCF Distributions $ — $ 7.4 $ 1.6 $ 9.6 Equity in income $ 0.3 $ 5.2 $ 2.1 $ 10.9 Cedar Cove JV Distributions $ 0.2 $ 0.2 $ 0.4 $ 0.5 Equity in loss $ (1.0) $ (0.5) $ (1.1) $ (0.9) Total Distributions $ 0.2 $ 7.6 $ 2.0 $ 10.1 Equity in income (loss) $ (0.7) $ 4.7 $ 1.0 $ 10.0 The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2020 and December 31, 2019 (in millions): June 30, 2020 December 31, 2019 GCF $ 39.7 $ 39.2 Cedar Cove JV 2.4 3.9 Total investment in unconsolidated affiliates $ 42.1 $ 43.1

Employee Incentive Plans

Employee Incentive Plans	6 Months Ended
	Jun. 30, 2020
Share-based Payment Arrangement [Abstract]
Employee Incentive Plans	(10) Employee Incentive Plans a. Long-Term Incentive Plans We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. 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 Six Months Ended 2020 2019 2020 2019 Cost of unit-based compensation charged to operating expense $ 2.0 $ 2.1 $ 4.2 $ 2.4 Cost of unit-based compensation charged to general and administrative expense 5.4 5.9 12.0 16.7 Total unit-based compensation expense $ 7.4 $ 8.0 $ 16.2 $ 19.1 Non-controlling interest in unit-based compensation $ — $ — $ — $ 0.5 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.7 $ 1.9 $ 3.8 $ 4.4 ____________________________ (1) For the three and six months ended June 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $6.8 million and $4.4 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three months ended June 30, 2019, the amount of related income tax expense recognized in net income excluded $0.1 million related to book-to-tax differences recorded upon vesting of restricted units. There was no income tax expense or benefit related to book-to-tax differences recorded upon vesting of restricted units for the six months ended June 30, 2020. b. ENLC Restricted Incentive Units ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2020 is provided below: Six Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 4,063,605 $ 13.85 Granted (1) 4,673,848 5.55 Vested (1)(2) (2,413,687) 10.35 Forfeited (478,304) 8.39 Non-vested, end of period 5,845,462 $ 9.11 Aggregate intrinsic value, end of period (in millions) $ 14.3 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 851,940 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2020 and 2019 is provided below (in millions): Three Months Ended Six Months Ended ENLC Restricted Incentive Units: 2020 2019 2020 2019 Aggregate intrinsic value of units vested $ 0.8 $ 0.5 $ 10.9 $ 12.9 Fair value of units vested $ 6.1 $ 0.5 $ 25.0 $ 13.1 As of June 30, 2020, there was $29.4 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted-average period of 1.8 years. c. ENLC Performance Units ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. The following table presents a summary of the performance units: Six Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,317,856 $ 14.22 Granted 1,161,986 7.32 Vested (1) (178,403) 30.56 Forfeited (37,646) 11.81 Non-vested, end of period 2,263,793 $ 9.43 Aggregate intrinsic value, end of period (in millions) $ 5.5 ____________________________ (1) Vested units included 67,775 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 and six months ended June 30, 2020 and 2019 is provided below (in millions). Three Months Ended Six Months Ended ENLC Performance Units: 2020 2019 2020 2019 Aggregate intrinsic value of units vested $ — $ — $ 0.9 $ 1.8 Fair value of units vested $ 0.5 $ — $ 5.5 $ 1.9 As of June 30, 2020, there was $14.5 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 1.7 years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: January 2020 March 2020 Grant-Date Fair Value $ 7.69 $ 1.13 Beginning TSR price $ 6.13 $ 1.25 Risk-free interest rate 1.62 % 0.42 % Volatility factor 37.00 % 51.00 % d. ENLK Restricted Incentive Units 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 six months ended June 30, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Six Months Ended ENLK Restricted Incentive Units: 2019 Aggregate intrinsic value of units vested $ 8.0 Fair value of units vested $ 7.2 e. ENLK Performance Units A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Six Months Ended ENLK Performance Units: 2019 Aggregate intrinsic value of units vested $ 2.1 Fair value of units vested $ 1.7

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) Derivatives Interest Rate Swaps In April 2019, we entered into an $850.0 million interest rate swap 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. 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 Six Months Ended 2020 2019 2020 2019 Change in fair value of interest rate swap $ 2.0 $ (13.5) $ (15.1) $ (13.5) Tax benefit (expense) (0.5) 3.6 3.5 3.6 Gain (loss) on designated cash flow hedge $ 1.5 $ (9.9) $ (11.6) $ (9.9) The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps, included in our consolidated income statement were as follows (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Interest expense (income) $ 3.7 $ (0.3) $ 5.0 $ (0.3) We expect to recognize an additional $18.4 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): June 30, 2020 December 31, 2019 Fair value of derivative liabilities—current $ (18.3) $ (5.6) Fair value of derivative liabilities—long-term (9.3) (6.8) Net fair value of interest rate swaps $ (27.6) $ (12.4) Commodity Swaps The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Change in fair value of derivatives $ (18.8) $ 7.2 $ (5.8) $ 5.2 Realized gain (loss) on derivatives (3.6) (0.3) 2.6 3.5 Gain (loss) on derivative activity $ (22.4) $ 6.9 $ (3.2) $ 8.7 The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): June 30, 2020 December 31, 2019 Fair value of derivative assets—current $ 9.9 $ 12.9 Fair value of derivative assets—long-term 5.8 4.3 Fair value of derivative liabilities—current (13.0) (8.8) Fair value of derivative liabilities—long-term (0.1) — Net fair value of commodity swaps $ 2.6 $ 8.4 Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at June 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022. June 30, 2020 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (172.5) $ (5.7) NGL (long contracts) Swaps Gallons 3.4 (0.1) Natural gas (short contracts) Swaps MMBtu (21.6) (0.2) Natural gas (long contracts) Swaps MMBtu 15.9 (0.6) Crude and condensate (short contracts) Swaps MMbbls (10.7) 7.2 Crude and condensate (long contracts) Swaps MMbbls 0.6 2.0 Total fair value of commodity swaps $ 2.6

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	(12) Fair Value Measurements Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2020 December 31, 2019 Interest rate swaps (1) $ (27.6) $ (12.4) Commodity swaps (2) $ 2.6 $ 8.4 ____________________________ (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 of Financial Instruments The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): June 30, 2020 December 31, 2019 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,749.0 $ 3,791.1 $ 4,764.3 $ 4,444.2 ____________________________ (1) The carrying value of long-term debt is reduced by debt issuance costs of $27.4 million and $29.8 million as of June 30, 2020 and December 31, 2019, 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	6 Months Ended
	Jun. 30, 2020
Segment Reporting [Abstract]
Segment Information	(13) Segment Information 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 and our crude operations in South Texas; • North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas; • 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; • Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; 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, our derivative activity, and our general corporate assets and expenses. We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended June 30, 2020 Natural gas sales $ 32.4 $ 14.6 $ 28.8 $ 68.6 $ — $ 144.4 NGL sales (0.1) — 0.5 280.9 — 281.3 Crude oil and condensate sales 87.0 — 5.0 14.9 — 106.9 Product sales 119.3 14.6 34.3 364.4 — 532.6 NGL sales—related parties 59.5 13.9 56.0 3.2 (132.5) 0.1 Crude oil and condensate sales—related parties — 0.4 0.1 — (0.6) (0.1) Product sales—related parties 59.5 14.3 56.1 3.2 (133.1) — Gathering and transportation 13.1 44.2 52.5 11.5 — 121.3 Processing 7.5 33.0 32.1 0.6 — 73.2 NGL services — 0.1 — 18.6 — 18.7 Crude services 5.0 — 4.6 11.0 — 20.6 Other services 0.2 0.2 0.1 0.4 — 0.9 Midstream services 25.8 77.5 89.3 42.1 — 234.7 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 204.6 106.4 179.8 409.7 (133.2) 767.3 Cost of sales (138.4) (18.9) (61.1) (312.5) 133.2 (397.7) Operating expenses (22.7) (18.5) (19.4) (27.5) — (88.1) Loss on derivative activity — — — — (22.4) (22.4) Segment profit (loss) $ 43.5 $ 69.0 $ 99.3 $ 69.7 $ (22.4) $ 259.1 Depreciation and amortization $ (31.0) $ (36.4) $ (54.1) $ (34.6) $ (2.1) $ (158.2) Impairments $ — $ — $ — $ (1.5) $ — $ (1.5) Capital expenditures $ 46.9 $ 3.0 $ 3.0 $ 15.6 $ 0.7 $ 69.2 Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended June 30, 2019 Natural gas sales $ (1.0) $ 31.9 $ 60.3 $ 102.6 $ — $ 193.8 NGL sales 0.8 8.7 4.3 498.8 — 512.6 Crude oil and condensate sales 632.0 — 28.6 83.5 — 744.1 Other — — (0.1) — — (0.1) Product sales 631.8 40.6 93.1 684.9 — 1,450.4 Natural gas sales—related parties 0.4 0.3 — — (0.7) — NGL sales—related parties 76.4 22.2 104.6 5.3 (208.5) — Crude oil and condensate sales—related parties 6.9 1.7 — — (8.6) — Product sales—related parties 83.7 24.2 104.6 5.3 (217.8) — Gathering and transportation 11.3 49.0 59.2 16.7 — 136.2 Processing 7.3 35.7 35.7 0.8 — 79.5 NGL services — — — 10.0 — 10.0 Crude services 5.3 — 5.2 12.9 — 23.4 Other services 2.9 0.3 0.2 0.2 — 3.6 Midstream services 26.8 85.0 100.3 40.6 — 252.7 NGL services—related parties — — — (0.3) 0.3 — Crude services—related parties — — 1.2 — (1.2) — Midstream services—related parties — — 1.2 (0.3) (0.9) — Revenue from contracts with customers 742.3 149.8 299.2 730.5 (218.7) 1,703.1 Cost of sales (680.5) (51.0) (159.4) (627.9) 218.7 (1,300.1) Operating expenses (28.4) (25.8) (26.1) (37.6) — (117.9) Gain on derivative activity — — — — 6.9 6.9 Segment profit $ 33.4 $ 73.0 $ 113.7 $ 65.0 $ 6.9 $ 292.0 Depreciation and amortization $ (30.1) $ (36.9) $ (47.6) $ (36.9) $ (2.2) $ (153.7) Goodwill $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7 Capital expenditures $ 52.4 $ 27.0 $ 70.3 $ 19.5 $ 2.4 $ 171.6 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2020 Natural gas sales $ 47.5 $ 34.7 $ 69.9 $ 150.2 $ — $ 302.3 NGL sales 0.1 0.3 1.7 654.6 — 656.7 Crude oil and condensate sales 372.0 — 21.2 73.3 — 466.5 Product sales 419.6 35.0 92.8 878.1 — 1,425.5 NGL sales—related parties 105.4 31.1 123.6 10.0 (270.1) — Crude oil and condensate sales—related parties 0.1 1.9 (0.1) — (1.9) — Product sales—related parties 105.5 33.0 123.5 10.0 (272.0) — Gathering and transportation 29.4 90.1 108.8 23.2 — 251.5 Processing 11.8 68.4 65.4 1.3 — 146.9 NGL services — 0.1 — 38.2 — 38.3 Crude services 9.2 — 8.9 21.6 — 39.7 Other services 0.8 0.5 0.2 0.8 — 2.3 Midstream services 51.2 159.1 183.3 85.1 — 478.7 Crude services—related parties — — 0.2 — (0.2) — Midstream services—related parties — — 0.2 — (0.2) — Revenue from contracts with customers 576.3 227.1 399.8 973.2 (272.2) 1,904.2 Cost of sales (452.3) (45.9) (154.8) (772.2) 272.2 (1,153.0) Operating expenses (48.2) (39.0) (42.3) (59.3) — (188.8) Loss on derivative activity — — — — (3.2) (3.2) Segment profit (loss) $ 75.8 $ 142.2 $ 202.7 $ 141.7 $ (3.2) $ 559.2 Depreciation and amortization $ (60.2) $ (73.6) $ (110.7) $ (72.4) $ (4.1) $ (321.0) Impairments $ (184.6) $ — $ — $ (169.9) $ — $ (354.5) Capital expenditures $ 132.9 $ 7.7 $ 11.5 $ 30.8 $ 1.1 $ 184.0 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2019 Natural gas sales $ 35.1 $ 82.5 $ 121.9 $ 224.8 $ — $ 464.3 NGL sales 0.6 18.0 13.2 1,071.9 — 1,103.7 Crude oil and condensate sales 1,212.8 — 58.2 142.3 — 1,413.3 Product sales 1,248.5 100.5 193.3 1,439.0 — 2,981.3 Natural gas sales—related parties 0.4 0.3 — — (0.7) — NGL sales—related parties 173.6 50.7 230.7 8.5 (463.5) — Crude oil and condensate sales—related parties 10.9 2.7 — — (13.6) — Product sales—related parties 184.9 53.7 230.7 8.5 (477.8) — Gathering and transportation 21.6 112.6 114.5 33.9 — 282.6 Processing 15.0 56.8 69.8 1.7 — 143.3 NGL services — — — 21.7 — 21.7 Crude services 10.5 — 9.2 26.7 — 46.4 Other services 4.4 0.5 (0.1) 0.4 — 5.2 Midstream services 51.5 169.9 193.4 84.4 — 499.2 NGL services—related parties — — — (3.3) 3.3 — Crude services—related parties — — 1.5 — (1.5) — Midstream services—related parties — — 1.5 (3.3) 1.8 — Revenue from contracts with customers 1,484.9 324.1 618.9 1,528.6 (476.0) 3,480.5 Cost of sales (1,356.7) (124.7) (343.6) (1,314.5) 476.0 (2,663.5) Operating expenses (56.2) (51.5) (51.5) (73.2) — (232.4) Gain on derivative activity — — — — 8.7 8.7 Segment profit $ 72.0 $ 147.9 $ 223.8 $ 140.9 $ 8.7 $ 593.3 Depreciation and amortization $ (58.0) $ (71.2) $ (93.7) $ (78.7) $ (4.2) $ (305.8) Impairments $ — $ — $ — $ (186.5) $ — $ (186.5) Goodwill $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7 Capital expenditures $ 148.3 $ 31.3 $ 178.5 $ 60.5 $ 4.0 $ 422.6 The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Segment profit $ 259.1 $ 292.0 $ 559.2 $ 593.3 General and administrative expenses (23.5) (32.2) (53.9) (83.6) Loss on disposition of assets (5.2) (0.1) (4.6) (0.1) Depreciation and amortization (158.2) (153.7) (321.0) (305.8) Impairments (1.5) — (354.5) (186.5) Loss on secured term loan receivable — (52.9) — (52.9) Operating income (loss) $ 70.7 $ 53.1 $ (174.8) $ (35.6) The table below represents information about segment assets as of June 30, 2020 and December 31, 2019 (in millions): Segment Identifiable Assets: June 30, 2020 December 31, 2019 Permian $ 2,268.5 $ 2,465.7 North Texas 1,061.7 1,135.8 Oklahoma 2,934.4 3,035.0 Louisiana 2,273.7 2,562.0 Corporate 180.5 137.3 Total identifiable assets $ 8,718.8 $ 9,335.8

Other Information

Other Information	6 Months Ended
	Jun. 30, 2020
Other Liabilities Disclosure [Abstract]
Other Information	(14) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: June 30, 2020 December 31, 2019 Natural gas and NGLs inventory $ 39.7 $ 43.4 Prepaid expenses and other 18.9 14.4 Other current assets $ 58.6 $ 57.8 Other current liabilities: June 30, 2020 December 31, 2019 Accrued interest $ 35.4 $ 37.1 Accrued wages and benefits, including taxes 15.8 31.5 Accrued ad valorem taxes 23.0 28.5 Capital expenditure accruals 20.6 42.4 Retention liability 11.0 8.7 Short-term lease liability 16.0 21.1 Suspense producer payments 12.1 13.8 Operating expense accruals 9.2 10.8 Other 17.1 12.3 Other current liabilities $ 160.2 $ 206.2

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2020
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, 2019. 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 Minimum Volume Commitments and Firm Transportation Contracts 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 and six months ended June 30, 2020, we had contractual commitments of $41.4 million and $83.2 million under our MVC contracts, respectively, and recorded $13.4 million and $25.2 million of revenue due to volume shortfalls, respectively.
Property and equipment	Property and Equipment Impairment Review. In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
Adopted Accounting Standards	Adopted Accounting Standards Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three and six months ended June 30, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.” Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.

Significant Accounting Polices

Significant Accounting Polices (Tables)	6 Months Ended
	Jun. 30, 2020
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 and six months ended June 30, 2020, we had contractual commitments of $41.4 million and $83.2 million under our MVC contracts, respectively, and recorded $13.4 million and $25.2 million of revenue due to volume shortfalls, respectively. MVC and Firm Transportation Commitments (in millions) (1) 2020 (remaining) $ 126.9 2021 115.1 2022 99.8 2023 90.5 2024 77.0 Thereafter 143.3 Total $ 652.6 ____________________________

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Changes in Carrying Value	The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2020 Customer relationships, beginning of period $ 1,795.8 $ (545.9) $ 1,249.9 Amortization expense — (61.8) (61.8) Retirements (1) (1.6) 0.6 (1.0) Customer relationships, end of period $ 1,794.2 $ (607.1) $ 1,187.1 ____________________________ (1) Intangible assets retired as a result of the disposition of certain non-core assets.
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 (remaining) $ 61.7 2021 123.4 2022 123.4 2023 123.4 2024 123.4 Thereafter 631.8 Total $ 1,187.1

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2020
Debt Disclosure [Abstract]
Summary of Debt	As of June 30, 2020 and December 31, 2019, long-term debt consisted of the following (in millions): June 30, 2020 December 31, 2019 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Consolidated Credit Facility due 2024 (1) $ 400.0 $ — $ 400.0 $ 350.0 $ — $ 350.0 Term Loan due 2021 (2) 850.0 — 850.0 850.0 — 850.0 ENLK’s 4.40% Senior unsecured notes due 2024 521.8 1.2 523.0 550.0 1.5 551.5 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.6) 720.2 750.0 (0.7) 749.3 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.4) 490.6 500.0 (0.5) 499.5 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 500.0 — 500.0 ENLK’s 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 ENLK’s 5.05% Senior unsecured notes due 2045 450.0 (5.8) 444.2 450.0 (5.9) 444.1 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,782.3 $ (5.9) 4,776.4 $ 4,800.0 $ (5.9) 4,794.1 Debt issuance cost (3) (27.4) (29.8) Long-term debt, net of unamortized issuance cost $ 4,749.0 $ 4,764.3 ____________________________ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.8% and 3.3% at June 30, 2020 and December 31, 2019, respectively. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.7% and 3.2% at June 30, 2020 and December 31, 2019, respectively. (3) Net of amortization of $12.6 million and $10.9 million at June 30, 2020 and December 31, 2019, respectively. For the three and six months ended June 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions): Three Months Ended Six Months Ended Debt repurchased $ 57.2 $ 67.7 Aggregate payments (30.8) (36.0) Net discount on repurchased debt (0.3) (0.3) Accrued interest on repurchased debt 0.6 0.6 Gain on extinguishment of debt $ 26.7 $ 32.0

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2020
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 Six Months Ended 2020 2019 2020 2019 Current income tax expense $ (0.4) $ (0.3) $ (0.7) $ (1.3) Deferred income tax benefit (expense) (11.3) 5.7 22.7 4.9 Income tax benefit (expense) $ (11.7) $ 5.4 $ 22.0 $ 3.6
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 Six Months Ended 2020 2019 2020 2019 Expected income tax benefit (expense) based on federal statutory rate $ (3.7) $ 4.5 $ 63.6 $ 41.2 State income tax benefit (expense), net of federal benefit (1.0) 0.4 7.0 4.3 Unit-based compensation (1) (6.8) (0.1) (4.4) — Non-deductible expense related to goodwill impairment — — (43.4) (43.8) Other (0.2) 0.6 (0.8) 1.9 Income tax benefit (expense) $ (11.7) $ 5.4 $ 22.0 $ 3.6 ____________________________ (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)	6 Months Ended
	Jun. 30, 2020
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2020 and 2019 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 Second Quarter of 2020 149,745 $ 16.8 August 13, 2020 2019 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019 Second Quarter of 2019 148,257 $ 17.1 August 13, 2019

Members' Equity (Tables)

Members' Equity (Tables)	6 Months Ended
	Jun. 30, 2020
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 Six Months Ended 2020 2019 2020 2019 Distributed earnings allocated to: Common units (1) $ 45.9 $ 137.8 $ 91.7 $ 247.2 Unvested restricted units (1) 0.8 1.8 1.6 3.0 Total distributed earnings $ 46.7 $ 139.6 $ 93.3 $ 250.2 Undistributed loss allocated to: Common units $ (42.2) $ (153.5) $ (369.6) $ (437.3) Unvested restricted units (0.4) (2.2) (6.4) (5.3) Total undistributed loss $ (42.6) $ (155.7) $ (376.0) $ (442.6) Net income (loss) allocated to: Common units $ 3.7 $ (15.7) $ (277.9) $ (190.1) Unvested restricted units 0.4 (0.4) (4.8) (2.3) Total net income (loss) $ 4.1 $ (16.1) $ (282.7) $ (192.4) Basic and diluted net income (loss) per unit: Basic $ 0.01 $ (0.03) $ (0.58) $ (0.44) Diluted $ 0.01 $ (0.03) $ (0.58) $ (0.44) ____________________________ (1) For the three months ended June 30, 2020 and 2019, distributed earnings represent a declared distribution of $0.09375 per unit payable on August 13, 2020 and a distribution of $0.283 per unit paid on August 13, 2019, respectively. (2) For the six months ended June 30, 2020, distributed earnings included a distribution of $0.09375 per unit paid on May 13, 2020 and a declared distribution of $0.09375 per unit payable on August 13, 2020. For the six months ended June 30, 2019, distributed earnings included distributions of $0.279 per unit paid on May 14, 2019 and $0.283 per unit paid on August 13, 2019.
Schedule of Unit Amounts Used to Computer Earnings per Unit	The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Basic weighted average units outstanding: Weighted average common units outstanding 489.3 487.2 489.0 439.9 Diluted weighted average units outstanding: Weighted average basic common units outstanding 489.3 487.2 489.0 439.9 Dilutive effect of non-vested restricted units (1) 1.1 — — — Total weighted average diluted common units outstanding 490.4 487.2 489.0 439.9 ____________________________ (1) All common unit equivalents were antidilutive for the six months ended June 30, 2020 and for the three and six months ended June 30, 2019 since a net loss existed for those periods.
Summary of Distribution Activity	A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2020 and 2019, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020 Second Quarter of 2020 $ 0.09375 August 13, 2020 2019 Fourth Quarter of 2018 $ 0.275 February 14, 2019 First Quarter of 2019 $ 0.279 May 14, 2019 Second Quarter of 2019 $ 0.283 August 13, 2019

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2020
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 GCF Distributions $ — $ 7.4 $ 1.6 $ 9.6 Equity in income $ 0.3 $ 5.2 $ 2.1 $ 10.9 Cedar Cove JV Distributions $ 0.2 $ 0.2 $ 0.4 $ 0.5 Equity in loss $ (1.0) $ (0.5) $ (1.1) $ (0.9) Total Distributions $ 0.2 $ 7.6 $ 2.0 $ 10.1 Equity in income (loss) $ (0.7) $ 4.7 $ 1.0 $ 10.0 The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2020 and December 31, 2019 (in millions): June 30, 2020 December 31, 2019 GCF $ 39.7 $ 39.2 Cedar Cove JV 2.4 3.9 Total investment in unconsolidated affiliates $ 42.1 $ 43.1

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Amounts Recognized in Consolidated Financial Statements	Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Cost of unit-based compensation charged to operating expense $ 2.0 $ 2.1 $ 4.2 $ 2.4 Cost of unit-based compensation charged to general and administrative expense 5.4 5.9 12.0 16.7 Total unit-based compensation expense $ 7.4 $ 8.0 $ 16.2 $ 19.1 Non-controlling interest in unit-based compensation $ — $ — $ — $ 0.5 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.7 $ 1.9 $ 3.8 $ 4.4 ____________________________ (1) For the three and six months ended June 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $6.8 million and $4.4 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three months ended June 30, 2019, the amount of related income tax expense recognized in net income excluded $0.1 million related to book-to-tax differences recorded upon vesting of restricted units. There was no income tax expense or benefit related to book-to-tax differences recorded upon vesting of restricted units for the six months ended June 30, 2020.
Schedule Of Restricted Stock Units Activity, ENLC	ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2020 is provided below: Six Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 4,063,605 $ 13.85 Granted (1) 4,673,848 5.55 Vested (1)(2) (2,413,687) 10.35 Forfeited (478,304) 8.39 Non-vested, end of period 5,845,462 $ 9.11 Aggregate intrinsic value, end of period (in millions) $ 14.3 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units, Vested and Fair Value Vested, ENLC	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2020 and 2019 is provided below (in millions): Three Months Ended Six Months Ended ENLC Restricted Incentive Units: 2020 2019 2020 2019 Aggregate intrinsic value of units vested $ 0.8 $ 0.5 $ 10.9 $ 12.9 Fair value of units vested $ 6.1 $ 0.5 $ 25.0 $ 13.1
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Six Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,317,856 $ 14.22 Granted 1,161,986 7.32 Vested (1) (178,403) 30.56 Forfeited (37,646) 11.81 Non-vested, end of period 2,263,793 $ 9.43 Aggregate intrinsic value, end of period (in millions) $ 5.5 ____________________________ (1) Vested units included 67,775 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 and six months ended June 30, 2020 and 2019 is provided below (in millions). Three Months Ended Six Months Ended ENLC Performance Units: 2020 2019 2020 2019 Aggregate intrinsic value of units vested $ — $ — $ 0.9 $ 1.8 Fair value of units vested $ 0.5 $ — $ 5.5 $ 1.9
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 2020 March 2020 Grant-Date Fair Value $ 7.69 $ 1.13 Beginning TSR price $ 6.13 $ 1.25 Risk-free interest rate 1.62 % 0.42 % Volatility factor 37.00 % 51.00 %
Summary of Restricted Incentive Unit Activity	Six Months Ended ENLK Restricted Incentive Units: 2019 Aggregate intrinsic value of units vested $ 8.0 Fair value of units vested $ 7.2
Summary of Performance Units, ENLP	Six Months Ended ENLK Performance Units: 2019 Aggregate intrinsic value of units vested $ 2.1 Fair value of units vested $ 1.7

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2020
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 Six Months Ended 2020 2019 2020 2019 Change in fair value of interest rate swap $ 2.0 $ (13.5) $ (15.1) $ (13.5) Tax benefit (expense) (0.5) 3.6 3.5 3.6 Gain (loss) on designated cash flow hedge $ 1.5 $ (9.9) $ (11.6) $ (9.9) The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps, included in our consolidated income statement were as follows (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Interest expense (income) $ 3.7 $ (0.3) $ 5.0 $ (0.3) The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Change in fair value of derivatives $ (18.8) $ 7.2 $ (5.8) $ 5.2 Realized gain (loss) on derivatives (3.6) (0.3) 2.6 3.5 Gain (loss) on derivative activity $ (22.4) $ 6.9 $ (3.2) $ 8.7
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): June 30, 2020 December 31, 2019 Fair value of derivative liabilities—current $ (18.3) $ (5.6) Fair value of derivative liabilities—long-term (9.3) (6.8) Net fair value of interest rate swaps $ (27.6) $ (12.4)
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): June 30, 2020 December 31, 2019 Fair value of derivative assets—current $ 9.9 $ 12.9 Fair value of derivative assets—long-term 5.8 4.3 Fair value of derivative liabilities—current (13.0) (8.8) Fair value of derivative liabilities—long-term (0.1) — Net fair value of commodity swaps $ 2.6 $ 8.4
Notional Amount and Fair Value of Derivative Instruments	Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at June 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022. June 30, 2020 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (172.5) $ (5.7) NGL (long contracts) Swaps Gallons 3.4 (0.1) Natural gas (short contracts) Swaps MMBtu (21.6) (0.2) Natural gas (long contracts) Swaps MMBtu 15.9 (0.6) Crude and condensate (short contracts) Swaps MMbbls (10.7) 7.2 Crude and condensate (long contracts) Swaps MMbbls 0.6 2.0 Total fair value of commodity swaps $ 2.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2020 December 31, 2019 Interest rate swaps (1) $ (27.6) $ (12.4) Commodity swaps (2) $ 2.6 $ 8.4 ____________________________ (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.
Schedule of the Estimated Fair Value of Financial Instruments	The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): June 30, 2020 December 31, 2019 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,749.0 $ 3,791.1 $ 4,764.3 $ 4,444.2 ____________________________

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2020
Segment Reporting [Abstract]
Summary of Financial Information	We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended June 30, 2020 Natural gas sales $ 32.4 $ 14.6 $ 28.8 $ 68.6 $ — $ 144.4 NGL sales (0.1) — 0.5 280.9 — 281.3 Crude oil and condensate sales 87.0 — 5.0 14.9 — 106.9 Product sales 119.3 14.6 34.3 364.4 — 532.6 NGL sales—related parties 59.5 13.9 56.0 3.2 (132.5) 0.1 Crude oil and condensate sales—related parties — 0.4 0.1 — (0.6) (0.1) Product sales—related parties 59.5 14.3 56.1 3.2 (133.1) — Gathering and transportation 13.1 44.2 52.5 11.5 — 121.3 Processing 7.5 33.0 32.1 0.6 — 73.2 NGL services — 0.1 — 18.6 — 18.7 Crude services 5.0 — 4.6 11.0 — 20.6 Other services 0.2 0.2 0.1 0.4 — 0.9 Midstream services 25.8 77.5 89.3 42.1 — 234.7 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 204.6 106.4 179.8 409.7 (133.2) 767.3 Cost of sales (138.4) (18.9) (61.1) (312.5) 133.2 (397.7) Operating expenses (22.7) (18.5) (19.4) (27.5) — (88.1) Loss on derivative activity — — — — (22.4) (22.4) Segment profit (loss) $ 43.5 $ 69.0 $ 99.3 $ 69.7 $ (22.4) $ 259.1 Depreciation and amortization $ (31.0) $ (36.4) $ (54.1) $ (34.6) $ (2.1) $ (158.2) Impairments $ — $ — $ — $ (1.5) $ — $ (1.5) Capital expenditures $ 46.9 $ 3.0 $ 3.0 $ 15.6 $ 0.7 $ 69.2 Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended June 30, 2019 Natural gas sales $ (1.0) $ 31.9 $ 60.3 $ 102.6 $ — $ 193.8 NGL sales 0.8 8.7 4.3 498.8 — 512.6 Crude oil and condensate sales 632.0 — 28.6 83.5 — 744.1 Other — — (0.1) — — (0.1) Product sales 631.8 40.6 93.1 684.9 — 1,450.4 Natural gas sales—related parties 0.4 0.3 — — (0.7) — NGL sales—related parties 76.4 22.2 104.6 5.3 (208.5) — Crude oil and condensate sales—related parties 6.9 1.7 — — (8.6) — Product sales—related parties 83.7 24.2 104.6 5.3 (217.8) — Gathering and transportation 11.3 49.0 59.2 16.7 — 136.2 Processing 7.3 35.7 35.7 0.8 — 79.5 NGL services — — — 10.0 — 10.0 Crude services 5.3 — 5.2 12.9 — 23.4 Other services 2.9 0.3 0.2 0.2 — 3.6 Midstream services 26.8 85.0 100.3 40.6 — 252.7 NGL services—related parties — — — (0.3) 0.3 — Crude services—related parties — — 1.2 — (1.2) — Midstream services—related parties — — 1.2 (0.3) (0.9) — Revenue from contracts with customers 742.3 149.8 299.2 730.5 (218.7) 1,703.1 Cost of sales (680.5) (51.0) (159.4) (627.9) 218.7 (1,300.1) Operating expenses (28.4) (25.8) (26.1) (37.6) — (117.9) Gain on derivative activity — — — — 6.9 6.9 Segment profit $ 33.4 $ 73.0 $ 113.7 $ 65.0 $ 6.9 $ 292.0 Depreciation and amortization $ (30.1) $ (36.9) $ (47.6) $ (36.9) $ (2.2) $ (153.7) Goodwill $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7 Capital expenditures $ 52.4 $ 27.0 $ 70.3 $ 19.5 $ 2.4 $ 171.6 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2020 Natural gas sales $ 47.5 $ 34.7 $ 69.9 $ 150.2 $ — $ 302.3 NGL sales 0.1 0.3 1.7 654.6 — 656.7 Crude oil and condensate sales 372.0 — 21.2 73.3 — 466.5 Product sales 419.6 35.0 92.8 878.1 — 1,425.5 NGL sales—related parties 105.4 31.1 123.6 10.0 (270.1) — Crude oil and condensate sales—related parties 0.1 1.9 (0.1) — (1.9) — Product sales—related parties 105.5 33.0 123.5 10.0 (272.0) — Gathering and transportation 29.4 90.1 108.8 23.2 — 251.5 Processing 11.8 68.4 65.4 1.3 — 146.9 NGL services — 0.1 — 38.2 — 38.3 Crude services 9.2 — 8.9 21.6 — 39.7 Other services 0.8 0.5 0.2 0.8 — 2.3 Midstream services 51.2 159.1 183.3 85.1 — 478.7 Crude services—related parties — — 0.2 — (0.2) — Midstream services—related parties — — 0.2 — (0.2) — Revenue from contracts with customers 576.3 227.1 399.8 973.2 (272.2) 1,904.2 Cost of sales (452.3) (45.9) (154.8) (772.2) 272.2 (1,153.0) Operating expenses (48.2) (39.0) (42.3) (59.3) — (188.8) Loss on derivative activity — — — — (3.2) (3.2) Segment profit (loss) $ 75.8 $ 142.2 $ 202.7 $ 141.7 $ (3.2) $ 559.2 Depreciation and amortization $ (60.2) $ (73.6) $ (110.7) $ (72.4) $ (4.1) $ (321.0) Impairments $ (184.6) $ — $ — $ (169.9) $ — $ (354.5) Capital expenditures $ 132.9 $ 7.7 $ 11.5 $ 30.8 $ 1.1 $ 184.0 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2019 Natural gas sales $ 35.1 $ 82.5 $ 121.9 $ 224.8 $ — $ 464.3 NGL sales 0.6 18.0 13.2 1,071.9 — 1,103.7 Crude oil and condensate sales 1,212.8 — 58.2 142.3 — 1,413.3 Product sales 1,248.5 100.5 193.3 1,439.0 — 2,981.3 Natural gas sales—related parties 0.4 0.3 — — (0.7) — NGL sales—related parties 173.6 50.7 230.7 8.5 (463.5) — Crude oil and condensate sales—related parties 10.9 2.7 — — (13.6) — Product sales—related parties 184.9 53.7 230.7 8.5 (477.8) — Gathering and transportation 21.6 112.6 114.5 33.9 — 282.6 Processing 15.0 56.8 69.8 1.7 — 143.3 NGL services — — — 21.7 — 21.7 Crude services 10.5 — 9.2 26.7 — 46.4 Other services 4.4 0.5 (0.1) 0.4 — 5.2 Midstream services 51.5 169.9 193.4 84.4 — 499.2 NGL services—related parties — — — (3.3) 3.3 — Crude services—related parties — — 1.5 — (1.5) — Midstream services—related parties — — 1.5 (3.3) 1.8 — Revenue from contracts with customers 1,484.9 324.1 618.9 1,528.6 (476.0) 3,480.5 Cost of sales (1,356.7) (124.7) (343.6) (1,314.5) 476.0 (2,663.5) Operating expenses (56.2) (51.5) (51.5) (73.2) — (232.4) Gain on derivative activity — — — — 8.7 8.7 Segment profit $ 72.0 $ 147.9 $ 223.8 $ 140.9 $ 8.7 $ 593.3 Depreciation and amortization $ (58.0) $ (71.2) $ (93.7) $ (78.7) $ (4.2) $ (305.8) Impairments $ — $ — $ — $ (186.5) $ — $ (186.5) Goodwill $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7 Capital expenditures $ 148.3 $ 31.3 $ 178.5 $ 60.5 $ 4.0 $ 422.6
Reconciliation of Profits to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended Six Months Ended 2020 2019 2020 2019 Segment profit $ 259.1 $ 292.0 $ 559.2 $ 593.3 General and administrative expenses (23.5) (32.2) (53.9) (83.6) Loss on disposition of assets (5.2) (0.1) (4.6) (0.1) Depreciation and amortization (158.2) (153.7) (321.0) (305.8) Impairments (1.5) — (354.5) (186.5) Loss on secured term loan receivable — (52.9) — (52.9) Operating income (loss) $ 70.7 $ 53.1 $ (174.8) $ (35.6)
Schedule of Segment Assets	The table below represents information about segment assets as of June 30, 2020 and December 31, 2019 (in millions): Segment Identifiable Assets: June 30, 2020 December 31, 2019 Permian $ 2,268.5 $ 2,465.7 North Texas 1,061.7 1,135.8 Oklahoma 2,934.4 3,035.0 Louisiana 2,273.7 2,562.0 Corporate 180.5 137.3 Total identifiable assets $ 8,718.8 $ 9,335.8

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 2020
Other Liabilities Disclosure [Abstract]
Schedule of Other Current Liabilities	The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: June 30, 2020 December 31, 2019 Natural gas and NGLs inventory $ 39.7 $ 43.4 Prepaid expenses and other 18.9 14.4 Other current assets $ 58.6 $ 57.8 Other current liabilities: June 30, 2020 December 31, 2019 Accrued interest $ 35.4 $ 37.1 Accrued wages and benefits, including taxes 15.8 31.5 Accrued ad valorem taxes 23.0 28.5 Capital expenditure accruals 20.6 42.4 Retention liability 11.0 8.7 Short-term lease liability 16.0 21.1 Suspense producer payments 12.1 13.8 Operating expense accruals 9.2 10.8 Other 17.1 12.3 Other current liabilities $ 160.2 $ 206.2

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2020	Jun. 30, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges			$ 1.9
Redemption of non-controlling interest			(4)	$ 0
Redeemable Non-Controlling Interest (Temporary Equity)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Redemption of non-controlling interest		$ 4	4
Louisiana
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges	$ 1.5		168
Minimum Volume Contract
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability	41.4		83.2
Contracts with customers, revenue recognition	$ 13.4		$ 25.2

Significant Accounting Polici_4

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Jun. 30, 2020USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 652.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-07-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 126.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 115.1
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]: 2022-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 99.8
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	$ 90.5
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	$ 77
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	$ 143.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 30.9	$ 31		$ 61.8	$ 61.9
Operating Segments | Louisiana
Finite-Lived Intangible Assets [Line Items]
Goodwill, impairment loss			$ 186.5
Operating Segments | Permian
Finite-Lived Intangible Assets [Line Items]
Goodwill, impairment loss				$ 184.6
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

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance			$ (545.9)
Amortization expense	$ (30.9)	$ (31)	(61.8)	$ (61.9)
Retirements, net			(1)
Accumulated Amortization, Ending Balance	(607.1)		(607.1)
Net Carrying Amount, Ending Balance	1,187.1		1,187.1
Louisiana
Finite-lived Intangible Assets [Roll Forward]
Retirements, gross			(1.6)
Customer relationships
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			1,795.8
Accumulated Amortization, Beginning Balance			(545.9)
Net Carrying Amount, Beginning Balance			1,249.9
Amortization expense			(61.8)
Retirements, accumulated amortization			0.6
Gross Carrying Amount, Ending Balance	1,794.2		1,794.2
Accumulated Amortization, Ending Balance	(607.1)		(607.1)
Net Carrying Amount, Ending Balance	$ 1,187.1		$ 1,187.1

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Amortization Expense (Details) $ in Millions	Jun. 30, 2020USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2020 (remaining)	$ 61.7
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8
Total	$ 1,187.1

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Related Party Transaction [Line Items]
Cost of sales	$ 397.7	$ 1,300.1	$ 1,153	$ 2,663.5
Accounts payable to related party	0.4		0.4		$ 1.1
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales	1.3	$ 5.8	4.2	$ 13.9
Accounts payable to related party	$ 0.4		$ 0.4		$ 1.1

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Debt Instrument
Outstanding principal	$ 4,782.3	$ 4,800
Premium (discount)	(5.9)	(5.9)
Long-term debt	4,776.4	4,794.1
Debt issuance costs	(27.4)	(29.8)
Long-term debt, net of unamortized issuance cost	4,749	4,764.3
Debt issuance cost accumulated amortization	12.6	10.9
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding principal	400	350
Premium (discount)	0	0
Long-term debt	$ 400	$ 350
Effective interest rate	1.80%	3.30%
Term Loan Due 2021
Debt Instrument
Outstanding principal	$ 850	$ 850
Premium (discount)	0	0
Long-term debt	$ 850	$ 850
Effective interest rate	1.70%	3.20%
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding principal	$ 521.8	$ 550
Premium (discount)	1.2	1.5
Long-term debt	$ 523	551.5
Stated interest rate	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding principal	$ 720.8	750
Premium (discount)	(0.6)	(0.7)
Long-term debt	$ 720.2	749.3
Stated interest rate	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding principal	$ 491	500
Premium (discount)	(0.4)	(0.5)
Long-term debt	$ 490.6	499.5
Stated interest rate	4.85%
5.375% Senior Notes Due 2029
Debt Instrument
Outstanding principal	$ 498.7	500
Premium (discount)	0	0
Long-term debt	$ 498.7	500
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)	(5.8)	(5.9)
Long-term debt	$ 444.2	444.1
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)	Dec. 11, 2018USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2019USD ($)
Debt Instrument
Payments on borrowings				$ 476,000,000	$ 2,131,400,000
Outstanding principal		$ 4,782,300,000		4,782,300,000		$ 4,800,000,000
Gain on extinguishment of debt		26,700,000	$ 0	32,000,000	$ 0
Letters of credit
Debt Instrument
Additional amount available (not to exceed)				1,750,000,000
Maximum borrowing capacity		2,250,000,000		2,250,000,000
Line of credit facility, fair value of amount outstanding		400,000,000		400,000,000
Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5
Outstanding principal		850,000,000		850,000,000		$ 850,000,000
Maximum | Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5.5
Conditional acquisition purchase price (or more)	$ 50,000,000
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity		$ 500,000,000		$ 500,000,000
Debt instrument, covenant, percentage of letter of credits guaranteed		105.00%		105.00%
Unsecured Debt | Letters of credit
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio		2.5		2.5
Ratio of consolidated indebtedness to consolidated EBITDA		5		5
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio		5.5		5.5
Unsecured Debt | Term Loan Due 2021
Debt Instrument
Face amount		$ 850,000,000		$ 850,000,000
Unsecured Debt | Minimum | Letters of credit
Debt Instrument
Conditional acquisition purchase price (or more)				$ 50,000,000
Unsecured Debt | LIBOR | Minimum | Letters of credit
Debt Instrument
Variable rate				1.125%
Unsecured Debt | LIBOR | Maximum | Letters of credit
Debt Instrument
Variable rate				2.00%
Unsecured Debt | Federal Funds | Letters of credit
Debt Instrument
Variable rate				0.50%
Unsecured Debt | Eurodollar | Letters of credit
Debt Instrument
Variable rate				1.00%
Unsecured Debt | Eurodollar | Minimum | Letters of credit
Debt Instrument
Variable rate				0.125%
Unsecured Debt | Eurodollar | Maximum | Letters of credit
Debt Instrument
Variable rate				1.00%
Line of Credit | Term Loan Due 2021
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio	2.5
Line of Credit | LIBOR | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate	1.00%
Line of Credit | LIBOR | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate	1.75%
Line of Credit | Federal Funds | Term Loan Due 2021
Debt Instrument
Variable rate	0.50%
Line of Credit | Eurodollar | Term Loan Due 2021
Debt Instrument
Variable rate	1.00%
Line of Credit | Eurodollar | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate	0.00%
Line of Credit | Eurodollar | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate	0.75%
ENLC | Letter of Credit | Letters of credit
Debt Instrument
Line of credit facility, fair value of amount outstanding		$ 23,000,000		$ 23,000,000

Long-Term Debt - Senior Unsecur

Long-Term Debt - Senior Unsecured Notes Repurchases (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2020
Debt Disclosure [Abstract]
Debt repurchased	$ 57.2	$ 67.7
Aggregate payments	(30.8)	(36)
Net discount on repurchased debt	(0.3)	(0.3)
Accrued interest on repurchased debt	0.6	0.6
Gain on extinguishment of debt	$ 26.7	$ 32

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.4)	$ (0.3)	$ (0.7)	$ (1.3)
Deferred income tax benefit (expense)	(11.3)	5.7	22.7	4.9
Income tax benefit (expense)	(11.7)	5.4	22	3.6
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (expense) based on federal statutory rate	(3.7)	4.5	63.6	41.2
State income tax benefit (expense), net of federal benefit	(1)	0.4	7	4.3
Unit-based compensation	(6.8)	(0.1)	(4.4)	0
Non-deductible expense related to goodwill impairment	0	0	(43.4)	(43.8)
Other	(0.2)	0.6	(0.8)	1.9
Income tax benefit (expense)	$ (11.7)	$ 5.4	$ 22	$ 3.6

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 58.3	$ 32.2
Deferred tax liabilities	$ (407.3)	$ (354)

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 13, 2019	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2020	Jun. 30, 2019
Partnership agreement
Distribution declared/unit (in dollars per share)		$ 0.09375	$ 0.09375	$ 0.1875	$ 0.283	$ 0.279	$ 0.275
Series B Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)		149,745	149,371	148,999	148,257	147,887	425,785
Cash distributions		$ 16.8	$ 16.8	$ 16.8	$ 17.1	$ 16.7	$ 16.5
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		59,897,920		59,599,550				59,897,920
Preferred units, outstanding (in shares)		59,897,920		59,599,550				59,897,920
Series C Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)		12,000,000			12,000,000			12,000,000	12,000,000
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		400,000		400,000				400,000
Preferred units, outstanding (in shares)		400,000		400,000				400,000
Common units | EnLink Midstream Partners, LP
Partnership agreement
Distribution declared/unit (in dollars per share)	$ 0.39

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	Aug. 13, 2020	May 13, 2020	Aug. 13, 2019	May 14, 2019	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2020	Jun. 30, 2019
Distributed earnings allocated to:
Total distributed earnings					$ 46.7			$ 139.6			$ 93.3	$ 250.2
Undistributed loss allocated to:
Total undistributed loss					(42.6)			(155.7)			(376)	(442.6)
Net income (loss) allocated to:
Total net income (loss)					$ 4.1			$ (16.1)			$ (282.7)	$ (192.4)
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)					$ 0.01			$ (0.03)			$ (0.58)	$ (0.44)
Diluted (in dollars per share)					0.01			(0.03)			$ (0.58)	$ (0.44)
Distribution declared/unit (in dollars per share)					$ 0.09375	$ 0.09375	$ 0.1875	$ 0.283	$ 0.279	$ 0.275
Distribution paid per unit (in dollars per share)		$ 0.09375	$ 0.283	$ 0.279
Subsequent Event
Basic and diluted net income (loss) per unit:
Distribution declared/unit (in dollars per share)	$ 0.09375
Distribution paid per unit (in dollars per share)	$ 0.09375
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings					$ 0.8			$ 1.8			$ 1.6	$ 3
Undistributed loss allocated to:
Total undistributed loss					(0.4)			(2.2)			(6.4)	(5.3)
Net income (loss) allocated to:
Total net income (loss)					0.4			(0.4)			(4.8)	(2.3)
Common units
Distributed earnings allocated to:
Total distributed earnings					45.9			137.8			91.7	247.2
Undistributed loss allocated to:
Total undistributed loss					(42.2)			(153.5)			(369.6)	(437.3)
Net income (loss) allocated to:
Total net income (loss)					$ 3.7			$ (15.7)			$ (277.9)	$ (190.1)

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Basic weighted average units outstanding:
Weighted average basic and diluted common units outstanding (in shares)	489.3	487.2	489	439.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	489.3	487.2	489	439.9
Dilutive effect of non-vested restricted units	1.1	0	0	0
Total weighted average diluted common units outstanding	490.4	487.2	489	439.9

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Equity method investments
Distributions	$ 0.2	$ 7.6	$ 2	$ 10.1
Equity in income (loss)	(0.7)	4.7	1	10
Total investment in unconsolidated affiliates	$ 42.1		$ 42.1		$ 43.1
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Distributions	$ 0	7.4	$ 1.6	9.6
Equity in income (loss)	$ 0.3	5.2	$ 2.1	10.9
Cedar Cove JV
Equity method investments
Ownership interest	30.00%		30.00%
Distributions	$ 0.2	0.2	$ 0.4	0.5
Equity in income (loss)	(1)	$ (0.5)	(1.1)	$ (0.9)
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	42.1		42.1		43.1
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	39.7		39.7		39.2
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ 2.4		$ 2.4		$ 3.9

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Allocation
Compensation expense	$ 7.4	$ 8	$ 16.2	$ 19.1
Amount of related income tax benefit recognized in net income (loss)	1.7	1.9	3.8	4.4
Restricted units
Allocation
Amount of related income tax benefit recognized in net income (loss)	(6.8)	(0.1)	(4.4)
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	2	2.1	4.2	2.4
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	5.4	5.9	12	16.7
Non-controlling interest in unit-based compensation
Allocation
Compensation expense	$ 0	$ 0	$ 0	$ 0.5

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended		6 Months Ended
	Mar. 31, 2020	Feb. 29, 2020	Jan. 31, 2020	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-Date Fair Value (in dollars per share)	$ 1.13		$ 7.69
Beginning TSR Price (in dollars per share)	$ 1.25		$ 6.13
Risk-free interest rate	0.42%		1.62%
Volatility factor	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)			4,063,605			4,063,605
Granted (in shares)		1,144,842				4,673,848
Vested (in shares)						(2,413,687)
Forfeited (in shares)						(478,304)
Non-vested, end of period (in shares)				5,845,462		5,845,462
Aggregate intrinsic value, end of period				$ 14.3		$ 14.3
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)			$ 13.85			$ 13.85
Granted (in dollars per share)						5.55
Vested (in dollars per share)						10.35
Forfeited (in dollars per share)						8.39
Non-vested, end of period (in dollars per share)				$ 9.11		$ 9.11
Vesting period						3 years
Fair value of units vested		$ 5.2
Units withheld for payroll taxes (in shares)						851,940
Unrecognized compensation cost related to non-vested restricted incentive units				$ 29.4		$ 29.4
Unrecognized compensation costs, weighted average period for recognition						1 year 9 months 18 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				6.1	$ 0.5	$ 25	$ 13.1
Aggregate intrinsic value of units vested				$ 0.8	0.5	$ 10.9	12.9
Unvested restricted units | EnLink Midstream Partners, LP
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							7.2
Aggregate intrinsic value of units vested							8
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)			1,317,856			1,317,856
Granted (in shares)						1,161,986
Vested (in shares)						(178,403)
Forfeited (in shares)						(37,646)
Non-vested, end of period (in shares)				2,263,793		2,263,793
Aggregate intrinsic value, end of period				$ 5.5		$ 5.5
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)			$ 14.22			$ 14.22
Granted (in dollars per share)						7.32
Vested (in dollars per share)						30.56
Forfeited (in dollars per share)						11.81
Non-vested, end of period (in dollars per share)				$ 9.43		$ 9.43
Fair value of units vested				$ 0.5	0	$ 5.5	1.9
Units withheld for payroll taxes (in shares)						67,775
Aggregate intrinsic value of units vested				0	$ 0	$ 0.9	1.8
Unrecognized compensation cost related to non-vested restricted incentive units				$ 14.5		$ 14.5
Unrecognized compensation costs, weighted average period for recognition						1 year 8 months 12 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%
Performance units | EnLink Midstream Partners, LP
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							1.7
Aggregate intrinsic value of units vested							$ 2.1

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($)		3 Months Ended				6 Months Ended
		Jun. 30, 2020		Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019	Apr. 30, 2019
Derivatives
Derivative, notional amount									$ 850,000,000
Derivative, fixed interest rate									2.28%
Income tax (benefit)		$ 500,000	[1]	$ (4,000,000)	$ (3,600,000)	$ (3,500,000)	$ (3,600,000)
Gain (loss) on designated cash flow hedge	[1]	1,500,000		$ (13,100,000)	(9,900,000)	(11,600,000)	(9,900,000)
(Loss) gain on interest rate swaps		3,700,000			(300,000)	5,000,000	(300,000)
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months		18,400,000				18,400,000
Fair value of derivative liabilities—current		(31,300,000)				(31,300,000)		$ (14,400,000)
Fair value of derivative liabilities—long-term		(9,400,000)				(9,400,000)		(6,800,000)
Interest rate swaps
Derivatives
Change in fair value of derivatives		2,000,000			$ (13,500,000)	(15,100,000)	$ (13,500,000)
Fair value of derivative liabilities—current		(18,300,000)				(18,300,000)		(5,600,000)
Fair value of derivative liabilities—long-term		(9,300,000)				(9,300,000)		(6,800,000)
Net fair value of commodity swaps		$ (27,600,000)				$ (27,600,000)		$ (12,400,000)
[1]	Includes a tax expense of $0.5 million and a tax benefit of $3.5 million for the three and six months ended June 30, 2020, respectively, and a tax benefit of $3.6 million for the three and six months ended June 30, 2019, respectively.

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Derivatives
Gain (loss) on derivative activity	$ (22.4)	$ 6.9	$ (3.2)	$ 8.7
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	(18.8)	7.2	(5.8)	5.2
Realized gain (loss) on derivatives	(3.6)	(0.3)	2.6	3.5
Gain (loss) on derivative activity	$ (22.4)	$ 6.9	$ (3.2)	$ 8.7

Derivatives - Fair Value of Ass

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Derivatives
Fair value of derivative assets—current	$ 9.9	$ 12.9
Fair value of derivative assets—long-term	5.8	4.3
Fair value of derivative liabilities—current	(31.3)	(14.4)
Fair value of derivative liabilities	9.4	6.8
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	9.9	12.9
Fair value of derivative assets—long-term	5.8	4.3
Fair value of derivative liabilities—current	(13)	(8.8)
Fair value of derivative liabilities	0.1	0
Net fair value of commodity swaps	$ 2.6	$ 8.4

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2020USD ($)MMBTUMMBblsgal	Dec. 31, 2019USD ($)
Derivatives
Net Fair Value	$ 2.6	$ 8.4
Commodity
Derivatives
Net Fair Value	2.6
Maximum loss if counterparties fail to perform	15.7
Possible reduction in maximum loss if counterparties fail to perform	$ 8.1
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	172.5
Net Fair Value	$ (5.7)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	3.4
Net Fair Value	$ (0.1)
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	21.6
Net Fair Value	$ (0.2)
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	15.9
Net Fair Value	$ (0.6)
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	10.7
Net Fair Value	$ 7.2
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	0.6
Net Fair Value	$ 2

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Interest rate swaps
Fair Value
Net Fair Value	$ (27.6)	$ (12.4)
Level 2 | Interest rate swaps | Recurring
Fair Value
Net Fair Value	(27.6)	(12.4)
Level 2 | Commodity swaps | Recurring
Fair Value
Net Fair Value	$ 2.6	$ 8.4

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Fair Value
Debt issuance costs	$ 27.4	$ 29.8
Carrying Value
Fair Value
Long-term debt	4,749	4,764.3
Fair Value
Fair Value
Long-term debt	$ 3,791.1	$ 4,444.2

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Segment Reporting
Revenue from contracts with customers	$ 767.3	$ 1,703.1	$ 1,904.2	$ 3,480.5
Cost of sales	(397.7)	(1,300.1)	(1,153)	(2,663.5)
Operating expenses	(88.1)	(117.9)	(188.8)	(232.4)
Gain (loss) on derivative activity	(22.4)	6.9	(3.2)	8.7
Segment profit (loss)	259.1	292	559.2	593.3
Depreciation and amortization	(158.2)	(153.7)	(321)	(305.8)
Impairments	(1.5)	0	(354.5)	(186.5)
Goodwill	0	1,123.7	0	1,123.7	$ 184.6
Capital expenditures	69.2	171.6	184	422.6
Permian
Segment Reporting
Revenue from contracts with customers	204.6	742.3	576.3	1,484.9
Cost of sales	(138.4)	(680.5)	(452.3)	(1,356.7)
Operating expenses	(22.7)	(28.4)	(48.2)	(56.2)
Gain (loss) on derivative activity	0	0	0	0
Segment profit (loss)	43.5	33.4	75.8	72
Depreciation and amortization	(31)	(30.1)	(60.2)	(58)
Impairments	0		(184.6)	0
Goodwill		184.6		184.6
Capital expenditures	46.9	52.4	132.9	148.3
North Texas
Segment Reporting
Revenue from contracts with customers	106.4	149.8	227.1	324.1
Cost of sales	(18.9)	(51)	(45.9)	(124.7)
Operating expenses	(18.5)	(25.8)	(39)	(51.5)
Gain (loss) on derivative activity	0	0	0	0
Segment profit (loss)	69	73	142.2	147.9
Depreciation and amortization	(36.4)	(36.9)	(73.6)	(71.2)
Impairments	0		0	0
Goodwill		125.7		125.7
Capital expenditures	3	27	7.7	31.3
Oklahoma
Segment Reporting
Revenue from contracts with customers	179.8	299.2	399.8	618.9
Cost of sales	(61.1)	(159.4)	(154.8)	(343.6)
Operating expenses	(19.4)	(26.1)	(42.3)	(51.5)
Gain (loss) on derivative activity	0	0	0	0
Segment profit (loss)	99.3	113.7	202.7	223.8
Depreciation and amortization	(54.1)	(47.6)	(110.7)	(93.7)
Impairments	0		0	0
Goodwill		813.4		813.4
Capital expenditures	3	70.3	11.5	178.5
Louisiana
Segment Reporting
Revenue from contracts with customers	409.7	730.5	973.2	1,528.6
Cost of sales	(312.5)	(627.9)	(772.2)	(1,314.5)
Operating expenses	(27.5)	(37.6)	(59.3)	(73.2)
Gain (loss) on derivative activity	0	0	0	0
Segment profit (loss)	69.7	65	141.7	140.9
Depreciation and amortization	(34.6)	(36.9)	(72.4)	(78.7)
Impairments	(1.5)		(169.9)	(186.5)
Goodwill		0		0
Capital expenditures	15.6	19.5	30.8	60.5
Corporate
Segment Reporting
Revenue from contracts with customers	(133.2)	(218.7)	(272.2)	(476)
Cost of sales	133.2	218.7	272.2	476
Operating expenses	0	0	0	0
Gain (loss) on derivative activity	(22.4)	6.9	(3.2)	8.7
Segment profit (loss)	(22.4)	6.9	(3.2)	8.7
Depreciation and amortization	(2.1)	(2.2)	(4.1)	(4.2)
Impairments	0		0	0
Goodwill		0		0
Capital expenditures	0.7	2.4	1.1	4
Product sales
Segment Reporting
Revenue from contracts with customers	532.6	1,450.4	1,425.5	2,981.3
Product sales | Permian
Segment Reporting
Revenue from contracts with customers	119.3	631.8	419.6	1,248.5
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers	14.6	40.6	35	100.5
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	34.3	93.1	92.8	193.3
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers	364.4	684.9	878.1	1,439
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers	144.4	193.8	302.3	464.3
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers	32.4	(1)	47.5	35.1
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers	14.6	31.9	34.7	82.5
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	28.8	60.3	69.9	121.9
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers	68.6	102.6	150.2	224.8
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers	281.3	512.6	656.7	1,103.7
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers	(0.1)	0.8	0.1	0.6
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers	0	8.7	0.3	18
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.5	4.3	1.7	13.2
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers	280.9	498.8	654.6	1,071.9
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	106.9	744.1	466.5	1,413.3
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers	87	632	372	1,212.8
Product sales, Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	5	28.6	21.2	58.2
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers	14.9	83.5	73.3	142.3
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, other
Segment Reporting
Revenue from contracts with customers		(0.1)
Product sales, other | Permian
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | North Texas
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | Oklahoma
Segment Reporting
Revenue from contracts with customers		(0.1)
Product sales, other | Louisiana
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | Corporate
Segment Reporting
Revenue from contracts with customers		0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	59.5	83.7	105.5	184.9
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	14.3	24.2	33	53.7
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	56.1	104.6	123.5	230.7
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	3.2	5.3	10	8.5
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(133.1)	(217.8)	(272)	(477.8)
Product sales, Natural gas sales—related parties
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0.4		0.4
Product sales, Natural gas sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.3		0.3
Product sales, Natural gas sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(0.7)		(0.7)
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers	0.1	0	0	0
Product sales, NGL sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	59.5	76.4	105.4	173.6
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	13.9	22.2	31.1	50.7
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	56	104.6	123.6	230.7
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	3.2	5.3	10	8.5
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(132.5)	(208.5)	(270.1)	(463.5)
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers	(0.1)	0	0	0
Product sales, Crude oil and condensate sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	0	6.9	0.1	10.9
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0.4	1.7	1.9	2.7
Product sales, Crude oil and condensate sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0	(0.1)	0
Product sales, Crude oil and condensate sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(0.6)	(8.6)	(1.9)	(13.6)
Midstream services
Segment Reporting
Revenue from contracts with customers	234.7	252.7	478.7	499.2
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers	25.8	26.8	51.2	51.5
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers	77.5	85	159.1	169.9
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers	89.3	100.3	183.3	193.4
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers	42.1	40.6	85.1	84.4
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers	121.3	136.2	251.5	282.6
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers	13.1	11.3	29.4	21.6
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers	44.2	49	90.1	112.6
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers	52.5	59.2	108.8	114.5
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers	11.5	16.7	23.2	33.9
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers	73.2	79.5	146.9	143.3
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers	7.5	7.3	11.8	15
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers	33	35.7	68.4	56.8
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers	32.1	35.7	65.4	69.8
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers	0.6	0.8	1.3	1.7
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers	18.7	10	38.3	21.7
Midstream services, NGL services | Permian
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, NGL services | North Texas
Segment Reporting
Revenue from contracts with customers	0.1	0	0.1	0
Midstream services, NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers	18.6	10	38.2	21.7
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers	20.6	23.4	39.7	46.4
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers	5	5.3	9.2	10.5
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers	4.6	5.2	8.9	9.2
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers	11	12.9	21.6	26.7
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers	0.9	3.6	2.3	5.2
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers	0.2	2.9	0.8	4.4
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers	0.2	0.3	0.5	0.5
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.2	0.2	(0.1)
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.4	0.2	0.8	0.4
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	1.2	0.2	1.5
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0	(0.3)	0	(3.3)
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(0.1)	(0.9)	(0.2)	1.8
Midstream services, NGL services, related party
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services, related party | Permian
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services, related party | North Texas
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		(0.3)		(3.3)
Midstream services, NGL services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.3		3.3
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	1.2	0.2	1.5
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	$ (0.1)	$ (1.2)	$ (0.2)	$ (1.5)

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Segment Reporting [Abstract]
Segment profit	$ 259.1	$ 292	$ 559.2	$ 593.3
General and administrative expenses	(23.5)	(32.2)	(53.9)	(83.6)
Loss on disposition of assets	(5.2)	(0.1)	(4.6)	(0.1)
Depreciation and amortization	(158.2)	(153.7)	(321)	(305.8)
Impairments	(1.5)	0	(354.5)	(186.5)
Loss on secured term loan receivable	0	(52.9)	0	(52.9)
Operating income (loss)	$ 70.7	$ 53.1	$ (174.8)	$ (35.6)

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Segment Reporting
Total identifiable assets	$ 8,718.8	$ 9,335.8
Permian
Segment Reporting
Total identifiable assets	2,268.5	2,465.7
North Texas
Segment Reporting
Total identifiable assets	1,061.7	1,135.8
Oklahoma
Segment Reporting
Total identifiable assets	2,934.4	3,035
Louisiana
Segment Reporting
Total identifiable assets	2,273.7	2,562
Corporate
Segment Reporting
Total identifiable assets	$ 180.5	$ 137.3

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Other current assets:
Natural gas and NGLs inventory	$ 39.7	$ 43.4
Prepaid expenses and other	18.9	14.4
Other current assets	58.6	57.8
Other current liabilities:
Accrued interest	35.4	37.1
Accrued wages and benefits, including taxes	15.8	31.5
Accrued ad valorem taxes	23	28.5
Capital expenditure accruals	20.6	42.4
Retention liability	11	8.7
Short-term lease liability	16	21.1
Suspense producer payments	12.1	13.8
Operating expense accruals	9.2	10.8
Other	17.1	12.3
Other current liabilities	$ 160.2	$ 206.2

Uncategorized Items - enlc-2020

Label	Element	Value
Accounting Standards Update [Extensible List]	us-gaap_AccountingStandardsUpdateExtensibleList	us-gaap:AccountingStandardsUpdate201602Member