EnLink Midstream (ENLC) 10-Q 7 Aug 19 2019 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2019	Aug. 01, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
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
Security Exchange Name	NYSE
Trading Symbol	ENLC
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		487,245,808
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2019
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, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 59	$ 100.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively	78.4	126.3
Accrued revenue and other	483.9	705.9
Related party	0	0.7
Fair value of derivative assets	9.5	28.6
Natural gas and NGLs inventory, prepaid expenses, and other	72.8	74.2
Total current assets	703.6	1,036.1
Property and equipment, net of accumulated depreciation of $3,198.1 and $2,967.4, respectively	7,023.5	6,846.7
Intangible assets, net of accumulated amortization of $484.1 and $422.2, respectively	1,311.7	1,373.6
Goodwill	1,123.7	1,310.2
Investment in unconsolidated affiliates	80	80.1
Fair value of derivative assets	7.1	4.1
Other assets, net	143.4	43.3
Total assets	10,393	10,694.1
Current liabilities:
Accounts payable and drafts payable	80.8	105.5
Accounts payable to related party	2	4.3
Accrued gas, NGLs, condensate, and crude oil purchases	377.1	500.4
Fair value of derivative liabilities	5.8	21.8
Current maturities of long-term debt	0	399.8
Other current liabilities	243.5	248.2
Total current liabilities	709.2	1,280
Long-term debt	4,612.5	4,031
Asset retirement obligations	15.2	14.8
Other long-term liabilities	93	20
Deferred tax liability, net	0	362.4
Fair value of derivative liabilities	10.6	2.4
Redeemable non-controlling interest	5.8	9.3
Members’ equity:
Members’ equity (487,227,012 and 181,309,981 units issued and outstanding, respectively)	3,324.6	1,730.9
Accumulated other comprehensive loss	(11.9)	(2)
Non-controlling interest	1,634	3,245.3
Total members’ equity	4,946.7	4,974.2
Total liabilities and members’ equity	$ 10,393	$ 10,694.1

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
ASSETS
Allowance for bad debt	$ 0.5	$ 0.3
Property and equipment, accumulated depreciation	3,198.1	2,967.4
Intangible assets, accumulated amortization	$ 484.1	$ 422.2
Members’ equity:
Common units issued (in shares)	487,227,012	181,309,981
Common units outstanding (in shares)	487,227,012	181,309,981

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues:
Revenue from contracts with customers		$ 1,703.1		$ 3,480.5	$ 3,541.1
Gain (loss) on derivative activity		6.9	$ (15.2)	8.7	(14.7)
Total revenues		1,710	1,764.7	3,489.2	3,526.4
Operating costs and expenses:
Cost of sales	[1]	1,300.1	1,325.6	2,663.5	2,707.1
Operating expenses		117.9	113.4	232.4	222.6
General and administrative		32.2	30.4	83.6	57.9
Loss on disposition of assets		0.1	1.2	0.1	1.3
Depreciation and amortization		153.7	145.3	305.8	283.4
Impairments		0	0	186.5	0
Loss on secured term loan receivable		52.9	0	52.9	0
Total operating costs and expenses		1,656.9	1,615.9	3,524.8	3,272.3
Operating income (loss)		53.1	148.8	(35.6)	254.1
Other income (expense):
Interest expense, net of interest income		(54.3)	(44.6)	(103.9)	(89.1)
Income from unconsolidated affiliates		4.7	4.4	10	7.4
Other income (expense)		0.2	(0.1)	0.2	0.2
Total other expense		(49.4)	(40.3)	(93.7)	(81.5)
Income (loss) before non-controlling interest and income taxes		3.7	108.5	(129.3)	172.6
Income tax benefit (provision)		5.4	(6.3)	3.6	(13.3)
Net income (loss)		9.1	102.2	(125.7)	159.3
Net income attributable to non-controlling interest		25.2	74.2	66.7	118.9
Net income (loss) attributable to ENLC		$ (16.1)	$ 28	$ (192.4)	$ 40.4
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ (0.03)	$ 0.15	$ (0.44)	$ 0.22
Diluted common unit (in dollars per share)		$ (0.03)	$ 0.15	$ (0.44)	$ 0.22
Product sales
Revenues:
Revenue from contracts with customers		$ 1,450.4	$ 1,435.1	$ 2,981.3	$ 2,934.3
Product sales—related parties
Revenues:
Revenue from contracts with customers		0	27.2	0	30.8
Midstream services
Revenues:
Revenue from contracts with customers		252.7	142.4	499.2	234.6
Midstream services—related parties
Revenues:
Revenue from contracts with customers		$ 0	$ 175.2	$ 0	$ 341.4
[1]	$5.8 million and $46.7 million for the three months ended June 30, 2019 and 2018 , respectively, and

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Statement [Abstract]
Related party cost of sales	$ 5.8	$ 46.7	$ 13.9	$ 80.8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) Statement - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2019		Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 9.1		$ 102.2	$ (125.7)	$ 159.3
Loss on designated cash flow hedge	[1]	(9.9)	[2]	0	(9.9)	0
Comprehensive income (loss)		(0.8)		102.2	(135.6)	159.3
Comprehensive income attributable to non-controlling interest		25.2		74.2	66.7	118.9
Comprehensive income (loss) attributable to ENLC		$ (26)		$ 28	$ (202.3)	$ 40.4
[1]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2019 , respectively, and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2018 , respectively.
[2]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ (3.6)	$ (3.6)

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Common Units	Accumulated Other Comprehensive Loss	Non-Controlling Interest	Redeemable Non-controlling interest (Temporary Equity)
Member equity, beginning balance at Dec. 31, 2017		$ 5,556.7		$ 1,924.2	$ (2)	$ 3,634.5
Units outstanding, beginning balance (in shares) at Dec. 31, 2017				180,600,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(2.9)		$ (2.9)		0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				400,000
Unit-based compensation		8.8		$ 4.4		4.4
Contributions from non-controlling interests		22.7				22.7
Distributions		(168.7)		(47.5)		(121.2)
Fair value adjustment related to redeemable non-controlling interest		(2.7)		0		(2.7)	$ 0
Net income (loss)		57.1		12.4		44.7	0
Issuance of common units for ENLK public common units related to the Merger		0.9				0.9
Change in equity due to issuance of units by ENLK		0.4		(1.3)		1.7
Member equity, end balance at Mar. 31, 2018		5,472.3		$ 1,889.3	(2)	3,585
Units outstanding, end balance (in shares) at Mar. 31, 2018				181,000,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2017							4.6
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		(2.7)		$ 0		(2.7)	0
Net income		57.1		12.4		44.7	0
Redeemable noncontrolling interest, ending balance at Mar. 31, 2018							4.6
Member equity, beginning balance at Dec. 31, 2017		5,556.7		$ 1,924.2	(2)	3,634.5
Units outstanding, beginning balance (in shares) at Dec. 31, 2017				180,600,000
Increase (Decrease) in Members' Equity
Loss on designated cash flow hedge	[1]	0
Member equity, end balance at Jun. 30, 2018		5,430.5		$ 1,871.9	(2)	3,560.6
Units outstanding, end balance (in shares) at Jun. 30, 2018				181,100,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2017							4.6
Redeemable noncontrolling interest, ending balance at Jun. 30, 2018							4.6
Member equity, beginning balance at Mar. 31, 2018		5,472.3		$ 1,889.3	(2)	3,585
Units outstanding, beginning balance (in shares) at Mar. 31, 2018				181,000,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.6)		$ (0.6)		0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				100,000
Unit-based compensation		8		$ 4		4
Contributions from non-controlling interests		31.6				31.6
Distributions		(182.5)		(48.2)		(134.3)
Loss on designated cash flow hedge	[1]	0
Fair value adjustment related to redeemable non-controlling interest		(0.7)		0		(0.7)	0
Net income (loss)		102.2		28		74.2	0
Change in equity due to issuance of units by ENLK		0.2		(0.6)		0.8
Member equity, end balance at Jun. 30, 2018		5,430.5		$ 1,871.9	(2)	3,560.6
Units outstanding, end balance (in shares) at Jun. 30, 2018				181,100,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2018							4.6
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		(0.7)		$ 0		(0.7)	0
Net income		102.2		28		74.2	0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2018							4.6
Member equity, beginning balance at Dec. 31, 2018		$ 4,974.2		$ 1,730.9	(2)	3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018		181,309,981		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		0	(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
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		2.5		$ 2.5		0	(2.1)
Net income		(134.8)		(176.3)		41.5	0
Redeemable noncontrolling interest, ending balance at Mar. 31, 2019							7.2
Member equity, beginning balance at Dec. 31, 2018		$ 4,974.2		$ 1,730.9	(2)	3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018		181,309,981		181,300,000
Increase (Decrease) in Members' Equity
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		487,227,012		487,200,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018							9.3
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)
Loss on designated cash flow hedge	[2]	(9.9)	[1]		(9.9)
Fair value adjustment related to redeemable non-controlling interest		0.2		0.2		0	(1.4)
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		487,227,012		487,200,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2019							7.2
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		$ 0.2		$ 0.2		0	(1.4)
Net income		$ 9.1		$ (16.1)		$ 25.2	0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2019							$ 5.8
[1]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2019 , respectively, and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2018 , respectively.
[2]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Statement of Stockholders' Equity [Abstract]
Income tax expense (benefit)	$ 3.6	$ 3.6

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities:
Net income (loss)	$ (125.7)	$ 159.3
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	186.5	0
Depreciation and amortization	305.8	283.4
Loss on secured term loan receivable	52.9	0
Non-cash unit-based compensation	19.1	14.7
(Gain) loss on derivatives recognized in net income (loss)	(8.7)	14.7
Cash settlements on derivatives	4.9	(0.4)
Amortization of debt issue costs, net discount (premium) of notes	2.9	2.5
Distribution of earnings from unconsolidated affiliates	9.7	9.5
Income from unconsolidated affiliates	(10)	(7.4)
Non-cash revenue from contract restructuring	0	(45.5)
Other operating activities	(7.9)	13.2
Changes in assets and liabilities net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	270.7	(46.7)
Natural gas and NGLs inventory, prepaid expenses, and other	(7.4)	(40.1)
Accounts payable, accrued product purchases, and other accrued liabilities	(171.3)	72.1
Net cash provided by operating activities	521.5	429.3
Cash flows from investing activities:
Additions to property and equipment	(428.4)	(404.4)
Other investing activities	1.5	2.6
Net cash used in investing activities	(426.9)	(401.8)
Cash flows from financing activities:
Proceeds from borrowings	2,320	1,361.8
Payments on borrowings	(2,131.4)	(832)
Payment of installment payable for EOGP acquisition	0	(250)
Debt financing costs	(9.7)	0
Conversion of restricted units, net of units withheld for taxes	(8.4)	(3.5)
Distribution to members	(188.2)	(95.7)
Distributions to non-controlling interests	(162.7)	(255.5)
Contributions by non-controlling interests	45.2	54.3
Other financing activities	(0.8)	(1.3)
Net cash used in financing activities	(136)	(21.9)
Net increase (decrease) in cash and cash equivalents	(41.4)	5.6
Cash and cash equivalents, beginning of period	100.4	31.2
Cash and cash equivalents, end of period	59	36.8
Supplemental disclosures of cash flow information:
Cash paid for interest	103.7	89.1
Cash paid for income taxes	1.2	0.4
Non-cash investing activities:
Non-cash accrual of property and equipment	(5.8)	(5)
Discounted secured term loan receivable from contract restructuring	$ 0	$ 47.7

General

General	6 Months Ended
	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	(1) General In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership and EOGP. 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 EnLink Midstream, LLC is a publicly traded 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.” Transfer of EOGP Interest On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP. Simplification of the Corporate Structure On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. As a result of the Merger: • Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in the issuance of 304,822,035 ENLC common units. • The General Partner’s incentive distribution rights in ENLK were eliminated. • The Series B Preferred Units continue to be issued and outstanding, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. See “ Note 8—Certain Provisions of the Partnership Agreement ” for additional information regarding the modified terms of the Series B Preferred Units. • ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled. • The Series C Preferred Units and all of ENLK’s then-existing senior notes continue to be issued and outstanding following the Merger. • Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan has been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time. • Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan has been modified such that the performance metric for such award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger. • ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “ Note 6—Long-Term Debt ” for additional information regarding the Term Loan. • We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, we entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “ Note 6—Long-Term Debt ” for additional information regarding the Consolidated Credit Facility. • We were required to allocate the goodwill in our Corporate reporting unit previously associated with the incentive distribution rights in ENLK granted to the General Partner which were created at the formation of ENLC in 2014, to the Permian, North Texas, Oklahoma, and Louisiana reporting units, which resulted in the recognition of a goodwill impairment of $186.5 million . See “ Note 3—Goodwill and Intangible Assets ” for more information on this transaction. • We reduced our deferred tax liability (“DTL”) by $399.0 million related to ENLC’s step-up in basis of ENLK’s underlying assets with the offsetting credit in members’ equity. See “ Note 7—Income Taxes ” for more information on the deferred tax asset (“DTA”). (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.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements are 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, 2018 . 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, 2019 , we had contractual commitments of $36.2 million and $74.7 million under our MVC contracts, respectively, and recorded $3.9 million and $7.7 million of revenue due to volume shortfalls, respectively. MVC and Firm Transportation Commitments (1) 2019 (remaining) $ 122.0 2020 243.9 2021 92.9 2022 82.5 2023 79.9 Thereafter 228.1 Total $ 849.3 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. (c) Secured Term Loan Receivable In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Under the original term loan agreement executed in May 2018, White Star was scheduled to make an installment payment of $19.5 million in April 2019. In November 2018 and again in February 2019, we amended the installment payment terms with the result that the single 2019 installment payment was split into two payments of $9.75 million in May 2019 and $10.75 million in October 2019. White Star defaulted on its May 2019 installment payment prior to filing for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While the outcome of the bankruptcy proceeding is uncertain, we do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. As a result, we have recorded a $52.9 million loss in our consolidated statement of operations for the three and six months ended June 30, 2019, which represents a full write-down of the second lien secured term loan. (d) Accounting Standards to be Adopted in Future Periods On August 29, 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”), which amends ASC 350-40, Internal-Use Software (“ASC 350-40”) to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. 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. We do not believe ASU 2018-15 will have a material impact on our financial statements, except 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 statement of operations, rather than “Depreciation and amortization.” We will adopt ASU 2018-15 prospectively effective January 1, 2020. (e) Adopted Accounting Standards Effective January 1, 2019, we adopted ASC 842, Leases , using the modified retrospective approach whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability. We applied certain practical expedients that were allowed in the adoption of ASC 842, including not reassessing existing contracts for lease arrangements, not reassessing existing lease classification, not recording a right-of-use asset or lease liability for leases of twelve months or less, and not separating lease and non-lease components of a lease arrangement. In connection with the adoption of ASC 842 in January 2019, we recorded a lease liability of $97.6 million , a right-of-use asset of $75.3 million , and a reduction of $22.6 million in other liabilities previously recorded related to lease incentives. For additional information about our adoption of ASC 842, refer to “ Note 5—Leases .”

Goodwill and Intangible Assets

Goodwill and Intangible Assets	6 Months Ended
	Jun. 30, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	(3) Goodwill and Intangible Assets Goodwill In March 2014, at the time of our transactions with Devon that led us to become publicly held, we recorded goodwill in our corporate reporting unit at ENLC that was associated with the General Partner’s incentive distribution rights in ENLK. Prior to the completion of the Merger in January 2019, ENLC’s aggregate fair value of its reporting units was in excess of the consolidated book value of its assets, including all goodwill, which would not have resulted in a goodwill impairment on a consolidated basis. Upon the completion of the Merger, in accordance with ASC 350, Intangibles-Goodwill and other (“ASC 350”), the portion of goodwill on our corporate reporting unit that was previously associated with the General Partner’s incentive distribution rights in ENLK was required to be reallocated to the four remaining reporting units based on the relative fair value of each of the reporting units . Due to the application of ASC 350, we were required to allocate goodwill to reporting units at which goodwill had previously been impaired due to book value in excess of fair value. As a result of the allocated goodwill, we recognized a $186.5 million impairment related to our Louisiana segment during the first quarter of 2019, which is reflected in the consolidated statement of operations for the six months ended June 30, 2019 . The table below provides a summary of our change in carrying amount of goodwill (in millions) for the six months ended June 30, 2019 , by segment. For the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2018 , there were no changes to the carrying amounts of goodwill. Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2019 Balance, beginning of period $ — $ — $ 190.3 $ — $ 1,119.9 $ 1,310.2 Goodwill allocation 184.6 125.7 623.1 186.5 (1,119.9 ) — Impairment — — — (186.5 ) — (186.5 ) Balance, end of period $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7 Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 5 to 20 years. The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2019 Customer relationships, beginning of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Amortization expense — (61.9 ) (61.9 ) Customer relationships, end of period $ 1,795.8 $ (484.1 ) $ 1,311.7 The weighted average amortization period is 15.0 years . Amortization expense was $31.0 million and $30.9 million for the three months ended June 30, 2019 and 2018 , respectively, and $61.9 million and $61.7 million for the six months ended June 30, 2019 and 2018 , respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2019 (remaining) $ 61.8 2020 123.7 2021 123.7 2022 123.7 2023 123.6 Thereafter 755.2 Total $ 1,311.7

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2019
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions (a) Transactions with ENLK Simplification of the Corporate Structure. On October 21, 2018, ENLK, ENLC, the General Partner , the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “ Note 1—General ” for more information on this transaction. Transfer of EOGP Interest. On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP. (b) Transactions with Devon On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP for aggregate consideration of $3.125 billion . Accordingly, Devon is no longer an affiliate of ENLK or ENLC. The sale did not affect our commercial arrangements with Devon, except that Devon agreed to extend through 2029 certain existing fixed-fee gathering and processing contracts related to the Bridgeport plant in north Texas and the Cana plant in Oklahoma. Prior to July 18, 2018, revenues from transactions with Devon are included in “Product sales—related parties” or “Midstream services—related parties” in the consolidated statement of operations. Revenues from transactions with Devon after July 18, 2018 are included in “Product sales” or “Midstream services” in the consolidated statement of operations. For the three and six months ended June 30, 2018 , Devon accounted for 11.5% and 10.6% , respectively, of our revenues. (c) Transactions with Cedar Cove JV For the three and six months ended June 30, 2019 , we recorded cost of sales of $5.8 million and $13.9 million , respectively, and for the three and six months ended June 30, 2018 , we recorded cost of sales of $9.5 million and $22.5 million , respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our central Oklahoma processing facilities. We had no accounts receivable balances related to transactions with the Cedar Cove JV at June 30, 2019 and $0.7 million at December 31, 2018 . Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $2.0 million and $4.3 million at June 30, 2019 and December 31, 2018 , respectively. Management believes the foregoing transactions with related parties were executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

Leases

Leases	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Leases	(5) Leases Effective with the adoption of ASC 842 in January 2019, we evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. The majority of our leases are for the following types of assets: • Office space- Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $62.5 million of our lease liability and $41.5 million of our right-of-use asset as of June 30, 2019 . These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred. • Compression and other field equipment- We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $28.2 million of our lease liability and $30.1 million of our right-of-use asset as of June 30, 2019 . Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred. • Office equipment- We rent office equipment for a monthly fee. These leases are typically for several years and represent $0.7 million of our lease liability and $0.7 million of our right-of-use asset as of June 30, 2019 . • Land and land easements- We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $15.0 million of our lease liability and $13.1 million of our right-of-use asset as of June 30, 2019 . Lease balances are recorded on the consolidated balance sheets as follows (in millions): June 30, 2019 Finance leases: Property and equipment $ 5.2 Accumulated depreciation (3.0 ) Property and equipment, net of accumulated depreciation $ 2.2 Other current liabilities $ 0.4 Operating leases: Other assets, net $ 83.2 Other current liabilities $ 21.7 Other long-term liabilities $ 84.3 Other lease information Weighted-average remaining lease term - Finance leases 0.3 years Weighted-average remaining lease term - Operating leases 10.7 years Weighted-average discount rate - Finance leases 9.3 % Weighted-average discount rate - Operating leases 5.2 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Finance lease expense: Amortization of right-of-use asset $ 2.3 $ 3.0 Operating lease expense: Long-term operating lease expense 8.3 14.6 Short-term lease expense 8.9 15.8 Variable lease expense 1.4 3.0 Total lease expense $ 20.9 $ 36.4 Other information about our leases are as follows (dollar amounts in millions, lease terms in years): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 0.4 $ 0.8 Cash payments for operating leases included in cash flows from operating activities $ 8.2 $ 15.4 Right-of-use assets obtained in exchange for operating lease liabilities $ 14.6 $ 95.2 The following table summarizes the maturity of our lease liability as of June 30, 2019 (in millions): Total 2019 (remaining) 2020 2021 2022 2023 Thereafter Undiscounted finance lease liability $ 0.4 $ 0.4 $ — $ — $ — $ — $ — Finance lease liability 0.4 0.4 — — — — — Undiscounted operating lease liability 146.5 13.5 22.4 16.1 9.4 8.9 76.2 Reduction due to present value (40.5 ) (2.6 ) (4.5 ) (3.8 ) (3.4 ) (3.1 ) (23.1 ) Operating lease liability 106.0 10.9 17.9 12.3 6.0 5.8 53.1 Total lease liability $ 106.4 $ 11.3 $ 17.9 $ 12.3 $ 6.0 $ 5.8 $ 53.1
Leases	(5) Leases Effective with the adoption of ASC 842 in January 2019, we evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. The majority of our leases are for the following types of assets: • Office space- Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $62.5 million of our lease liability and $41.5 million of our right-of-use asset as of June 30, 2019 . These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred. • Compression and other field equipment- We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $28.2 million of our lease liability and $30.1 million of our right-of-use asset as of June 30, 2019 . Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred. • Office equipment- We rent office equipment for a monthly fee. These leases are typically for several years and represent $0.7 million of our lease liability and $0.7 million of our right-of-use asset as of June 30, 2019 . • Land and land easements- We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $15.0 million of our lease liability and $13.1 million of our right-of-use asset as of June 30, 2019 . Lease balances are recorded on the consolidated balance sheets as follows (in millions): June 30, 2019 Finance leases: Property and equipment $ 5.2 Accumulated depreciation (3.0 ) Property and equipment, net of accumulated depreciation $ 2.2 Other current liabilities $ 0.4 Operating leases: Other assets, net $ 83.2 Other current liabilities $ 21.7 Other long-term liabilities $ 84.3 Other lease information Weighted-average remaining lease term - Finance leases 0.3 years Weighted-average remaining lease term - Operating leases 10.7 years Weighted-average discount rate - Finance leases 9.3 % Weighted-average discount rate - Operating leases 5.2 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Finance lease expense: Amortization of right-of-use asset $ 2.3 $ 3.0 Operating lease expense: Long-term operating lease expense 8.3 14.6 Short-term lease expense 8.9 15.8 Variable lease expense 1.4 3.0 Total lease expense $ 20.9 $ 36.4 Other information about our leases are as follows (dollar amounts in millions, lease terms in years): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 0.4 $ 0.8 Cash payments for operating leases included in cash flows from operating activities $ 8.2 $ 15.4 Right-of-use assets obtained in exchange for operating lease liabilities $ 14.6 $ 95.2 The following table summarizes the maturity of our lease liability as of June 30, 2019 (in millions): Total 2019 (remaining) 2020 2021 2022 2023 Thereafter Undiscounted finance lease liability $ 0.4 $ 0.4 $ — $ — $ — $ — $ — Finance lease liability 0.4 0.4 — — — — — Undiscounted operating lease liability 146.5 13.5 22.4 16.1 9.4 8.9 76.2 Reduction due to present value (40.5 ) (2.6 ) (4.5 ) (3.8 ) (3.4 ) (3.1 ) (23.1 ) Operating lease liability 106.0 10.9 17.9 12.3 6.0 5.8 53.1 Total lease liability $ 106.4 $ 11.3 $ 17.9 $ 12.3 $ 6.0 $ 5.8 $ 53.1

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of June 30, 2019 and December 31, 2018 , long-term debt consisted of the following (in millions): June 30, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt ENLC Credit Facility, due 2019 (1) $ — $ — $ — $ 111.4 $ — $ 111.4 Consolidated Credit Facility due 2024 (2) 200.0 — 200.0 — — — Term Loan due 2021 (3) 850.0 — 850.0 850.0 — 850.0 ENLK's 2.70% Senior unsecured notes due 2019 (4) — — — 400.0 — 400.0 ENLK’s 4.40% Senior unsecured notes due 2024 550.0 1.6 551.6 550.0 1.8 551.8 ENLK’s 4.15% Senior unsecured notes due 2025 750.0 (0.8 ) 749.2 750.0 (0.9 ) 749.1 ENLK’s 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.5 ) 499.5 ENLC’s 5.375% Senior unsecured notes due 2029 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 (6.1 ) 443.9 450.0 (6.2 ) 443.8 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 500.0 (0.1 ) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,650.0 $ (6.1 ) 4,643.9 $ 4,461.4 $ (6.1 ) 4,455.3 Debt issuance cost (5) (31.4 ) (24.5 ) Less: Current maturities of long-term debt (4) — (399.8 ) Long-term debt, net of unamortized issuance cost $ 4,612.5 $ 4,031.0 ____________________________ (1) Bore interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.4% at December 31, 2018 . In connection with the closing of the Merger, the ENLC Credit Facility was canceled, and all outstanding borrowings were refinanced through borrowings on the Consolidated Credit Facility. Since the borrowings under the ENLC Credit Facility were refinanced with long-term debt, they are classified as “Long-term debt” on the consolidated balance sheet as of December 31, 2018. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.0% at June 30, 2019 . (3) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% and 3.9% at June 30, 2019 and December 31, 2018 , respectively. (4) ENLK’s 2.70% senior unsecured notes matured on April 1, 2019. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of December 31, 2018 . (5) Net of amortization of $11.9 million and $16.5 million at June 30, 2019 and December 31, 2018 , respectively. Issuance and Repayment of Senior Unsecured Notes On April 9, 2019, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.375% senior unsecured notes due June 1, 2029 (the “2029 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $496.5 million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $400.0 million outstanding aggregate principal amount of ENLK’s 2.70% senior unsecured notes due 2019, and for general limited liability company purposes. Consolidated Credit Facility On December 11, 2018, ENLC entered into the Consolidated Credit Facility, which 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 ( $200.0 million as of June 30, 2019 ), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ( $5.0 million as of June 30, 2019). 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 (the LIBOR Rate) 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, 2019 , we were in compliance with and expect to be in compliance with the 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. On December 11, 2018, ENLK borrowed $850.0 million under the Term Loan and used the net proceeds to repay obligations outstanding under the ENLK Credit Facility. 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, the outstanding balance immediately becomes due, and 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, 2019 . 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 the Eurodollar Rate (the LIBOR Rate) 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, 2019 , we were in compliance with and expect to be in compliance with the covenants of the Term Loan for at least the next twelve months.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	(7) Income Taxes The components of our income tax benefit (provision) are as follows (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Current income tax benefit (provision) $ (0.3 ) $ 0.3 $ (1.3 ) $ (0.9 ) Deferred income tax benefit (provision) 5.7 (6.6 ) 4.9 (12.4 ) Income tax benefit (provision) $ 5.4 $ (6.3 ) $ 3.6 $ (13.3 ) The following schedule reconciles total income tax benefit (provision) and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Expected income tax benefit (provision) based on federal statutory rate $ 4.5 $ (7.2 ) $ 41.2 $ (11.3 ) State income tax benefit (provision), net of federal benefit 0.4 (0.4 ) 4.3 (1.7 ) Non-deductible expense related to asset impairment — — (43.8 ) — Other 0.5 1.3 1.9 (0.3 ) Income tax benefit (provision) $ 5.4 $ (6.3 ) $ 3.6 $ (13.3 ) Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax assets, net of deferred tax liabilities, are included in “Other assets, net” in the consolidated balance sheets at June 30, 2019. Our deferred income tax assets and liabilities as of June 30, 2019 and December 31, 2018 are as follows (in millions): June 30, 2019 December 31, 2018 Deferred income tax assets: Federal net operating loss carryforward $ 106.2 $ 67.9 State net operating loss carryforward 16.6 11.7 Total deferred tax assets 122.8 79.6 Deferred tax liabilities: Property, equipment, and intangible assets (1) (78.2 ) (440.6 ) Other (0.1 ) (1.4 ) Total deferred tax liabilities (78.3 ) (442.0 ) Deferred tax asset (liability), net $ 44.5 $ (362.4 ) ____________________________ (1) Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment . As a result of the Merger, we acquired all issued and outstanding ENLK common units that were not already held by us or our subsidiaries in exchange for the issuance of ENLC common units. See “ Note 1—General ” for more information regarding this transaction. This was a taxable exchange to our unitholders, and we received a step-up in tax basis of the underlying assets acquired. In accordance with ASC 810, Consolidation , the step-up in our basis reduced our DTL by $399.0 million at the time of the Merger, and the resulting DTA will be realized over the tax-basis depreciable life of the underlying assets. As of June 30, 2019 , we had federal net operating loss carryforwards of $505.5 million that represent a net deferred tax asset of $106.2 million . As of December 31, 2018 , we had federal net operating loss carryforwards of $323.6 million that represent a net deferred tax asset of $67.9 million . These carryforwards will begin expiring in 2028 through 2038. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.

Certain Provisions of the Partn

Certain Provisions of the Partnership Agreement	6 Months Ended
	Jun. 30, 2019
Partners' Capital [Abstract]
Certain Provisions of the Partnership Agreement	(8) Certain Provisions of the Partnership Agreement (a) ENLK Series B Preferred Units Prior to the closing of the Merger, Series B Preferred Unit distributions were payable quarterly in cash at an amount equal to $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into ENLK common units over the Cash Distribution Component, divided by (ii) the issue price of $15.00 (the “Issue Price”). Following the closing of the Merger, and beginning with the quarter ended March 31, 2019, the holder of the Series B Preferred Units is entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units as described below. The quarterly in-kind distribution (the “Series B PIK Distribution”) equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the exchange ratio of 1.15 ENLC common units for each Series B Preferred Unit, subject to certain adjustments (the “Series B Exchange Ratio”), over (2) the Cash Distribution Component, divided by (y) the Issue Price. The quarterly cash distribution consists of the Cash Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments). A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2019 and 2018 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 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 2018 Fourth Quarter of 2017 413,658 $ 16.0 February 13, 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 (b) ENLK Series C Preferred Units Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15 th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15 th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11% . ENLK distributed $12.0 million to holders of Series C Preferred Units during the three and six months ended June 30, 2019 and 2018 , respectively. (c) ENLK Common Unit Distributions A summary of ENLK’s distribution activity relating to the common units for periods prior to the Merger is provided below: Declaration period Distribution/unit Date paid/payable 2019 Fourth Quarter of 2018 $ 0.39 February 13, 2019 2018 Fourth Quarter of 2017 $ 0.39 February 13, 2018 First Quarter of 2018 $ 0.39 May 14, 2018 Second Quarter of 2018 $ 0.39 August 13, 2018 (d) Allocation of ENLK Income Prior to the closing of the Merger and for the three and six months ended June 30, 2018 , net income was allocated to the General Partner in an amount equal to its incentive distribution rights. Prior to the closing of the Merger, ENLK was required to pay the General Partner incentive distributions in the amount of 13.0% of ENLK distributions in excess of $0.25 per unit, 23.0% of ENLK distributions in excess of $0.3125 per unit, and 48.0% of ENLK distributions in excess of $0.375 per unit. The General Partner was not entitled to incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units converted into common units or (ii) the Series C Preferred Units. At the closing of the Merger, the General Partner’s incentive distribution rights in ENLK were eliminated. For the three and six months ended June 30, 2018, the General Partner’s share of net income consisted of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner . The net income allocated to the General Partner is as follows (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Income allocation for incentive distributions $ — $ 14.8 $ — $ 29.6 Unit-based compensation attributable to ENLC’s restricted and performance units (6.4 ) (4.0 ) (18.5 ) (8.4 ) General Partner share of net income (loss) (0.2 ) 0.4 0.2 0.6 General Partner interest in EOGP acquisition — 12.6 2.4 16.8 General Partner interest in net income (loss) $ (6.6 ) $ 23.8 $ (15.9 ) $ 38.6

Members' Equity

Members' Equity	6 Months Ended
	Jun. 30, 2019
Earnings Per Share [Abstract]
Members' Equity	(9) Members' Equity (a) Issuance of ENLC Common Units related to the Merger In connection with the consummation of the Merger, we issued 304,822,035 ENLC common units in exchange for all of the outstanding ENLK common units not previously owned by us. (b) ENLC Equity Distribution Agreement On February 22, 2019, ENLC entered into the ENLC EDA with the Sales Agents to sell up to $400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program. Under the ENLC EDA, ENLC may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. ENLC has no obligation to sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of August 7, 2019 , ENLC has not sold any common units under the ENLC EDA. (c) 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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Distributed earnings allocated to: Common units (1)(2) $ 137.8 $ 48.3 $ 247.2 $ 95.9 Unvested restricted units (1)(2) 1.8 0.8 3.0 1.3 Total distributed earnings $ 139.6 $ 49.1 $ 250.2 $ 97.2 Undistributed loss allocated to: Common units $ (153.5 ) $ (20.8 ) $ (437.3 ) $ (56.1 ) Unvested restricted units (2.2 ) (0.3 ) (5.3 ) (0.7 ) Total undistributed loss $ (155.7 ) $ (21.1 ) $ (442.6 ) $ (56.8 ) Net income (loss) allocated to: Common units $ (15.7 ) $ 27.5 $ (190.1 ) $ 39.8 Unvested restricted units (0.4 ) 0.5 (2.3 ) 0.6 Total net income (loss) $ (16.1 ) $ 28.0 $ (192.4 ) $ 40.4 Basic and diluted net income (loss) per unit: Basic $ (0.03 ) $ 0.15 $ (0.44 ) $ 0.22 Diluted $ (0.03 ) $ 0.15 $ (0.44 ) $ 0.22 ____________________________ (1) For the three months ended June 30, 2019 and 2018 , distributed earnings represent a declared distribution of $0.283 per unit payable on August 13, 2019 and a distribution of $0.267 per unit paid on August 14, 2018 , respectively. (2) For the six months ended June 30, 2019 , distributed earnings included a distribution of $0.279 per unit paid on May 14, 2019 and a declared distribution of $0.283 per unit payable on August 13, 2019 . For the six months ended June 30, 2018 , distributed earnings included distributions of $0.263 per unit paid on May 15, 2018 and $0.267 per unit paid on August 14, 2018 . 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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Basic weighted average units outstanding: Weighted average common units outstanding 487.2 181.0 439.9 181.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 487.2 181.0 439.9 181.0 Dilutive effect of non-vested restricted units (1) — 1.2 — 1.0 Total weighted average diluted common units outstanding 487.2 182.2 439.9 182.0 ___________________________ (1) All common unit equivalents were antidilutive for the three and six months ended June 30, 2019 since a net loss existed for those periods. (d) Distributions A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2019 and 2018 , respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2019 Fourth Quarter of 2018 $ 0.275 February 14, 2019 First Quarter of 2019 $ 0.279 May 14, 2019 Second Quarter 2019 $ 0.283 August 13, 2019 2018 Fourth Quarter of 2017 $ 0.259 February 14, 2018 First Quarter of 2018 $ 0.263 May 15, 2018 Second Quarter 2018 $ 0.267 August 14, 2018

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(10) Investment in Unconsolidated Affiliates As of June 30, 2019 , our unconsolidated investments consisted of a 38.75% ownership in GCF and an approximate 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 2019 2018 2019 2018 GCF Distributions $ 7.4 $ 5.4 $ 9.6 $ 11.1 Equity in income $ 5.2 $ 4.8 $ 10.9 $ 9.4 Cedar Cove JV Contributions $ — $ 0.1 $ — $ 0.1 Distributions $ 0.2 $ — $ 0.5 $ 0.3 Equity in loss $ (0.5 ) $ (0.4 ) $ (0.9 ) $ (2.0 ) Total Contributions $ — $ 0.1 $ — $ 0.1 Distributions $ 7.6 $ 5.4 $ 10.1 $ 11.4 Equity in income $ 4.7 $ 4.4 $ 10.0 $ 7.4 The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2019 and December 31, 2018 (in millions): June 30, 2019 December 31, 2018 GCF $ 43.2 $ 41.9 Cedar Cove JV 36.8 38.2 Total investment in unconsolidated affiliates $ 80.0 $ 80.1

Employee Incentive Plans

Employee Incentive Plans	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Employee Incentive Plans	(11) Employee Incentive Plans (a) Long-Term Incentive Plans Prior to the Merger, ENLC and ENLK each had similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the 2014 Plan, and ENLK granted unit-based awards under the GP Plan. As of the closing of the Merger, (i) ENLC assumed all obligations in respect of the GP Plan and the outstanding awards granted thereunder (the “Legacy ENLK Awards”) and (ii) the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. In addition, as of the closing of the Merger, the performance metric of each Legacy ENLK Award and each then outstanding award under the 2014 Plan with performance-based vesting conditions was modified as discussed in (c) and (e) below. Following the consummation of the Merger, no additional awards will be granted under the GP Plan. We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended June 30, Six Months Ended 2019 2018 2019 2018 Cost of unit-based compensation charged to operating expense $ 2.1 $ 2.3 $ 2.4 $ 4.3 Cost of unit-based compensation charged to general and administrative expense 5.9 7.3 16.7 10.4 Total unit-based compensation expense $ 8.0 $ 9.6 $ 19.1 $ 14.7 Non-controlling interest in unit-based compensation $ — $ 3.6 $ 0.5 $ 5.5 Amount of related income tax benefit recognized in net income $ 1.9 $ 1.2 $ 4.4 $ 1.9 (b) EnLink Midstream Partners, LP Restricted Incentive Units ENLK restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLK common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2019 is provided below: Six Months Ended EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,556,270 $ 14.43 Vested (1) (722,853 ) 10.02 Forfeited (4,490 ) 11.93 Converted to ENLC (2) (1,828,927 ) 16.11 Non-vested, end of period — $ — ____________________________ (1) Vested units included 249,201 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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, 2019 and 2018 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 under the GP Plan. Three Months Ended June 30, Six Months Ended June 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2019 2018 2019 2018 Aggregate intrinsic value of units vested $ — $ 0.4 $ 8.0 $ 9.1 Fair value of units vested $ — $ 0.5 $ 7.2 $ 13.3 (c) EnLink Midstream Partners, LP Performance Units Prior to the Merger, the General Partner granted performance awards under the GP Plan. The performance award agreements provided that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder was dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplated that the Peer Companies for an individual performance award (the “Subject Award”) were the companies comprising the AMZ, excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units would vest based on the percentile ranking of the average of ENLK’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the closing of the Merger, these performance-based Legacy ENLK Awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger . 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 performance units ranges from zero to 200% of the performance units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. The fair value of each performance unit was estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLK among the designated Peer Companies; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years . The following table presents a summary of the performance units: Six Months Ended EnLink Midstream Partners, LP Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 451,669 $ 17.74 Vested (1) (161,410 ) 10.54 Converted to ENLC (2) (290,259 ) 28.31 Non-vested, end of period — $ — ____________________________ (1) Vested units included 62,403 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC unit-based performance awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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 and 2018 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 under the GP Plan. No performance units vested for the three months ended June 30, 2018. Six Months Ended June 30, EnLink Midstream Partners, LP Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 2.1 $ 2.0 Fair value of units vested $ 1.7 $ 4.1 (d) EnLink Midstream, LLC Restricted Incentive Units ENLC restricted incentive units are 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, 2019 is provided below: Six Months Ended EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,425,867 $ 14.62 Granted (1) 1,835,494 11.44 Vested (1)(2) (1,255,211 ) 10.47 Forfeited (272,185 ) 10.86 Converted from ENLK (3) 2,103,266 14.01 Non-vested, end of period 4,837,231 $ 14.44 Aggregate intrinsic value, end of period (in millions) $ 48.8 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2019, ENLC granted 420,842 restricted incentive units with a fair value of $4.8 million to officers and certain employees as bonus payments for 2018, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 420,778 units withheld for payroll taxes paid on behalf of employees. (3) Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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, 2019 and 2018 is provided below (in millions): Three Months Ended June 30, Six Months Ended June 30, EnLink Midstream, LLC Restricted Incentive Units: 2019 2018 2019 2018 Aggregate intrinsic value of units vested $ 0.5 $ 0.4 $ 12.9 $ 9.3 Fair value of units vested $ 0.5 $ 0.4 $ 13.1 $ 13.5 As of June 30, 2019 , there was $38.2 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.9 years . For all restricted incentive unit awards granted after March 8, 2019 to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of the grantee’s employment: (i) due to retirement, (ii) by ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants agreement) or the applicable Covered Termination occurs after a change of control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date. (e) EnLink Midstream, LLC’s 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 units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. Performance awards granted prior to March 8, 2019 provided that the vesting of performance units granted was dependent on the achievement of certain TSR performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. Prior to the Merger, vesting of the performance units was based on the percentile ranking of the EnLink TSR for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the effective time of the Merger, these performance-based awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger. The following table presents a summary of the performance units: Six Months Ended EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 418,149 $ 19.15 Granted 931,469 13.02 Vested (1) (161,286 ) 11.71 Forfeited (92,422 ) 20.41 Converted from ENLK (2) 333,798 25.84 Non-vested, end of period 1,429,708 $ 17.48 Aggregate intrinsic value, end of period (in millions) $ 14.4 ____________________________ (1) Vested units included 62,219 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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 and 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2019 and 2018, respectively. Six Months Ended June 30, EnLink Midstream, LLC Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 1.8 $ 1.9 Fair value of units vested $ 1.9 $ 4.2 As of June 30, 2019 , there was $16.7 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 2.0 years . In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to, among other things: (i) provide that the awards granted thereunder did not vest due to the closing of the GIP Transaction, and (ii) increase the minimum vesting of units from zero to 100% as described in our Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2018. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $2.1 million compensation cost over the life of these ENLC performance units. In connection with the Merger, Legacy ENLK Awards with “performance-based” vesting and payment conditions were modified to reflect the Performance Metric Adjustment (as defined in the Merger Agreement) as described in our Current Report on Form 8-K filed with the Commission on January 29, 2019. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $0.7 million in compensation costs over the life of the Legacy ENLK Awards. 2019 Performance Unit Awards For all performance awards granted after March 8, 2019 to the grantee, the vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) the TSR performance of ENLC (the “ENLC TSR”) and a performance goal based on cash flow (“Cash Flow”). At the time of grant, the Board of Directors of the managing member of ENLC (the “Board”) will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the “Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”). One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the ENLC TSR relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period. The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies: Performance Level Achieved ENLC TSR Position Relative to Designated Peer Companies Vesting percentage of the Tranche TSR Units Below Threshold Less than 25% 0% Threshold Equal to 25% 50% Target Equal to 50% 100% Maximum Greater than or Equal to 75% 200% Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. The following table sets out the levels at which the Tranche CF Units will be eligible to vest (using linear interpolation) based on the Cash Flow performance of ENLC for the performance period ending December 31, 2019: Performance Level ENLC’s Achieved Cash Flow Vesting percentage of the Tranche CF Units Below Threshold Less than $1.43 0% Threshold Equal to $1.43 50% Target Equal to $1.55 100% Maximum Greater than or Equal to $1.72 200% The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the Designated Peer Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC among the Designated Peer Companies or Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years . The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream, LLC Performance Units: June 2019 March 2019 Beginning TSR price $ 9.84 $ 10.92 Risk-free interest rate 1.72 % 2.42 % Volatility factor 33.50 % 33.86 % Distribution yield 11.5 % 9.7 %

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(12) Derivatives Interest Rate Swaps We periodically enter into interest rate swaps during the debt issuance process to hedge variability in future long-term debt interest payments that may result from changes in the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued or to hedge variability in cash flows on our variable-rate debt. We designate interest rate swaps as cash flow hedges in accordance with ASC 815. 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 2.27825% in exchange for LIBOR-based variable interest through December 2021. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). There is no ineffectiveness related to this hedge. In May 2017, we entered into an interest rate swap in connection with the issuance of ENLK’s 2047 Notes. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. For the three and six months ended June 30, 2019 , we recorded $9.9 million , net of a tax benefit of $3.6 million , into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps. For the three and six months ended June 30, 2019 , we realized a gain of $0.3 million related to the monthly settlement of our interest rate swaps and an immaterial amount of amortization, which we recorded into interest expense, net of interest income from accumulated other comprehensive loss . For the three and six months ended June 30, 2018 , we recorded an immaterial amount into interest expense, net of interest income from accumulated other comprehensive loss . We expect to recognize $3.4 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, 2019 Fair value of derivative liabilities—current $ (3.3 ) Fair value of derivative liabilities—long-term (10.2 ) Net fair value of derivatives $ (13.5 ) Commodity Swaps We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our commodity risk management policy does not allow us to take speculative positions with our derivative contracts. We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs, and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate, and crude oil, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage. Assets and liabilities related to our commodity swap contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity in “ Gain (loss) on derivative activity ” in the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities. The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Change in fair value of derivatives $ 7.2 $ (10.5 ) $ 5.2 $ (14.0 ) Realized gain (loss) on derivatives (0.3 ) (4.7 ) 3.5 (0.7 ) Gain (loss) on derivative activity $ 6.9 $ (15.2 ) $ 8.7 $ (14.7 ) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): June 30, 2019 December 31, 2018 Fair value of derivative assets—current $ 9.5 $ 28.6 Fair value of derivative assets—long-term 7.1 4.1 Fair value of derivative liabilities—current (2.5 ) (21.8 ) Fair value of derivative liabilities—long-term (0.4 ) (2.4 ) Net fair value of derivatives $ 13.7 $ 8.5 Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at June 30, 2019 (in millions). The remaining term of the contracts extend no later than December 2022. June 30, 2019 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (24.2 ) $ 3.0 NGL (long contracts) Swaps Gallons 15.0 (0.6 ) Natural gas (short contracts) Swaps MMBtu (2.4 ) 0.4 Natural gas (long contracts) Swaps MMBtu 6.3 (0.4 ) Crude and condensate (short contracts) Swaps MMbbls (12.3 ) 5.6 Crude and condensate (long contracts) Swaps MMbbls 0.8 5.7 Total fair value of derivatives $ 13.7 On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing swap contracts, the maximum loss on our gross receivable position of $16.6 million as of June 30, 2019 would be reduced to $13.8 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	(13) Fair Value Measurements ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our derivative contracts primarily consist of commodity swap contracts and interest rate swap contracts, which are not traded on a public exchange. The fair values of commodity swap contracts and interest rate swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices and interest rates that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate, and credit risk and are classified as Level 2 in hierarchy. Net assets measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2019 December 31, 2018 Interest rate swaps (1) $ (13.5 ) $ — Commodity swaps (2) $ 13.7 $ 8.5 ____________________________ (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, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 4,612.5 $ 4,480.4 $ 4,430.8 $ 4,065.0 Secured term loan receivable (2) $ — $ — $ 51.1 $ 51.1 ____________________________ (1) The carrying value of long-term debt as of December 31, 2018 includes current maturities. The carrying value of long-term debt is reduced by debt issuance costs of $31.4 million and $24.5 million at June 30, 2019 and December 31, 2018 , respectively. The respective fair values do not factor in debt issuance costs. (2) In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “ Note 2—Significant Accounting Policies .” The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. As of June 30, 2019 , we had total borrowings under senior unsecured notes of $3.6 billion maturing between 2024 and 2047 with fixed interest rates ranging from 4.15% to 5.60% . As of December 31, 2018, we had total borrowings under senior unsecured notes of $3.5 billion maturing between 2019 and 2047 with fixed interest rates ranging from 2.70% to 5.60% . The fair values of all senior unsecured notes as of June 30, 2019 and December 31, 2018 were based on Level 2 inputs from third-party market quotations. The fair values of the secured term loan receivable were calculated using Level 2 inputs from third-party banks.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Segment Information	(14) Segment Information Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources. As of December 31, 2018 , our reportable operating segments consisted of the following: (i) natural gas gathering, processing, transmission, and fractionation operations located in north Texas and the Permian Basin primarily in west Texas, (ii) natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana, (iii) natural gas gathering and processing operations located throughout Oklahoma, and (iv) crude rail, truck, pipeline, and barge facilities in west Texas, south Texas, Louisiana, Oklahoma, and ORV. Effective January 1, 2019, we are reporting financial performance in five segments: Permian, North Texas, Oklahoma, Louisiana, and Corporate. Crude and condensate operations are combined regionally with natural gas and NGL operations in the Oklahoma and Permian segments, and ORV operations are included in the Louisiana segment. We have recast the segment information for the three and six months ended June 30, 2018 to conform to the current period presentation. Identification of the majority of our operating segments is based principally upon geographic regions served: • Permian Segment . The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in west Texas and eastern New Mexico 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, 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 Three Months Ended June 30, 2018 Natural gas sales $ 33.5 $ 23.3 $ 37.9 $ 122.7 $ — $ 217.4 NGL sales 0.3 — 3.6 627.9 — 631.8 Crude oil and condensate sales 511.5 — 23.3 51.1 — 585.9 Product sales 545.3 23.3 64.8 801.7 — 1,435.1 Natural gas sales—related parties — — 1.9 — — 1.9 NGL sales—related parties 122.9 11.5 140.4 28.9 (278.7 ) 25.0 Crude oil and condensate sales—related parties 0.4 0.4 0.3 0.1 (0.9 ) 0.3 Product sales—related parties 123.3 11.9 142.6 29.0 (279.6 ) 27.2 Gathering and transportation 7.6 6.8 25.6 16.7 — 56.7 Processing 7.3 2.2 47.4 1.1 — 58.0 NGL services — — — 10.3 — 10.3 Crude services 0.1 — — 14.9 — 15.0 Other services 2.0 — (0.1 ) 0.5 — 2.4 Midstream services 17.0 9.0 72.9 43.5 — 142.4 Gathering and transportation—related parties — 61.4 38.7 — — 100.1 Processing—related parties — 46.8 23.1 — — 69.9 Crude services—related parties 4.3 — 0.7 — — 5.0 Other services—related parties — 0.4 (0.2 ) — — 0.2 Midstream services—related parties 4.3 108.6 62.3 — — 175.2 Revenue from contracts with customers 689.9 152.8 342.6 874.2 (279.6 ) 1,779.9 Cost of sales (633.9 ) (32.0 ) (170.1 ) (769.2 ) 279.6 (1,325.6 ) Operating expenses (24.7 ) (28.4 ) (20.8 ) (39.5 ) — (113.4 ) Loss on derivative activity — — — — (15.2 ) (15.2 ) Segment profit $ 31.3 $ 92.4 $ 151.7 $ 65.5 $ (15.2 ) $ 325.7 Depreciation and amortization $ (27.3 ) $ (31.6 ) $ (46.4 ) $ (37.4 ) $ (2.6 ) $ (145.3 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 52.8 $ 5.5 $ 140.0 $ 18.8 $ 1.1 $ 218.2 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 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2018 Natural gas sales $ 71.2 $ 68.6 $ 86.0 $ 247.7 $ — $ 473.5 NGL sales 0.8 — 5.5 1,236.3 — 1,242.6 Crude oil and condensate sales 1,088.7 — 45.2 84.3 — 1,218.2 Product sales 1,160.7 68.6 136.7 1,568.3 — 2,934.3 Natural gas sales—related parties — — 2.4 — — 2.4 NGL sales—related parties 206.8 20.5 240.5 34.5 (474.9 ) 27.4 Crude oil and condensate sales—related parties 1.9 0.8 0.7 0.2 (2.6 ) 1.0 Product sales—related parties 208.7 21.3 243.6 34.7 (477.5 ) 30.8 Gathering and transportation 13.8 14.6 41.2 34.3 — 103.9 Processing 11.1 2.2 56.4 1.7 — 71.4 NGL services — — — 26.9 — 26.9 Crude services 0.1 — 0.1 27.7 — 27.9 Other services 3.7 0.3 — 0.5 — 4.5 Midstream services 28.7 17.1 97.7 91.1 — 234.6 Gathering and transportation—related parties — 114.0 73.4 — — 187.4 Processing—related parties — 98.4 45.2 — — 143.6 Crude services—related parties 8.6 — 1.4 — — 10.0 Other services—related parties — 0.4 — — — 0.4 Midstream services—related parties 8.6 212.8 120.0 — — 341.4 Revenue from contracts with customers 1,406.7 319.8 598.0 1,694.1 (477.5 ) 3,541.1 Cost of sales (1,308.0 ) (81.9 ) (309.4 ) (1,485.3 ) 477.5 (2,707.1 ) Operating expenses (48.5 ) (56.8 ) (41.5 ) (75.8 ) — (222.6 ) Loss on derivative activity — — — — (14.7 ) (14.7 ) Segment profit $ 50.2 $ 181.1 $ 247.1 $ 133.0 $ (14.7 ) $ 596.7 Depreciation and amortization $ (54.1 ) $ (62.9 ) $ (88.5 ) $ (73.3 ) $ (4.6 ) $ (283.4 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 116.4 $ 8.0 $ 243.9 $ 28.8 $ 2.3 $ 399.4 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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Segment profit $ 292.0 $ 325.7 $ 593.3 $ 596.7 General and administrative expenses (32.2 ) (30.4 ) (83.6 ) (57.9 ) Loss on disposition of assets (0.1 ) (1.2 ) (0.1 ) (1.3 ) Depreciation and amortization (153.7 ) (145.3 ) (305.8 ) (283.4 ) Impairments — — (186.5 ) — Loss on secured term loan receivable (52.9 ) — (52.9 ) — Operating income (loss) $ 53.1 $ 148.8 $ (35.6 ) $ 254.1 The table below represents information about segment assets as of June 30, 2019 and December 31, 2018 (in millions): Segment Identifiable Assets: June 30, 2019 December 31, 2018 Permian $ 2,386.1 $ 2,096.8 North Texas 1,346.7 1,308.2 Oklahoma 3,881.7 3,209.5 Louisiana 2,575.1 2,734.5 Corporate 203.4 1,345.1 Total identifiable assets $ 10,393.0 $ 10,694.1

Other Information

Other Information	6 Months Ended
	Jun. 30, 2019
Other Liabilities Disclosure [Abstract]
Other Information	(15) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Natural gas and NGLs inventory, prepaid expenses, and other: June 30, 2019 December 31, 2018 Natural gas and NGLs inventory $ 51.5 $ 41.3 Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1) — 19.4 Prepaid expenses and other 21.3 13.5 Natural gas and NGLs inventory, prepaid expenses, and other $ 72.8 $ 74.2 ____________________________ (1) In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “ Note 2—Significant Accounting Policies .” Other current liabilities: June 30, 2019 December 31, 2018 Accrued interest $ 41.1 $ 37.5 Accrued wages and benefits, including taxes 18.6 37.2 Accrued ad valorem taxes 25.8 28.1 Capital expenditure accruals 44.9 50.6 Onerous performance obligations — 9.0 Short-term lease liability 22.1 1.5 Suspense producer payments 15.4 34.6 Deferred revenue 48.6 6.6 Other 27.0 43.1 Other current liabilities $ 243.5 $ 248.2

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements are 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, 2018 . 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, 2019 , we had contractual commitments of $36.2 million and $74.7 million under our MVC contracts, respectively, and recorded $3.9 million and $7.7 million of revenue due to volume shortfalls, respectively.
Accounting Standards to be Adopted in Future Periods and Adopted Accounting Standards	Accounting Standards to be Adopted in Future Periods On August 29, 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”), which amends ASC 350-40, Internal-Use Software (“ASC 350-40”) to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. 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. We do not believe ASU 2018-15 will have a material impact on our financial statements, except 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 statement of operations, rather than “Depreciation and amortization.” We will adopt ASU 2018-15 prospectively effective January 1, 2020. (e) Adopted Accounting Standards Effective January 1, 2019, we adopted ASC 842, Leases , using the modified retrospective approach whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability. We applied certain practical expedients that were allowed in the adoption of ASC 842, including not reassessing existing contracts for lease arrangements, not reassessing existing lease classification, not recording a right-of-use asset or lease liability for leases of twelve months or less, and not separating lease and non-lease components of a lease arrangement. In connection with the adoption of ASC 842 in January 2019, we recorded a lease liability of $97.6 million , a right-of-use asset of $75.3 million , and a reduction of $22.6 million in other liabilities previously recorded related to lease incentives. For additional information about our adoption of ASC 842, refer to “ Note 5—Leases .”

Significant Accounting Polices

Significant Accounting Polices (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 , we had contractual commitments of $36.2 million and $74.7 million under our MVC contracts, respectively, and recorded $3.9 million and $7.7 million of revenue due to volume shortfalls, respectively. MVC and Firm Transportation Commitments (1) 2019 (remaining) $ 122.0 2020 243.9 2021 92.9 2022 82.5 2023 79.9 Thereafter 228.1 Total $ 849.3 ____________________________ (1) Amounts do not represent expected shortfall under these commitments.

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The table below provides a summary of our change in carrying amount of goodwill (in millions) for the six months ended June 30, 2019 , by segment. For the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2018 , there were no changes to the carrying amounts of goodwill. Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2019 Balance, beginning of period $ — $ — $ 190.3 $ — $ 1,119.9 $ 1,310.2 Goodwill allocation 184.6 125.7 623.1 186.5 (1,119.9 ) — Impairment — — — (186.5 ) — (186.5 ) Balance, end of period $ 184.6 $ 125.7 $ 813.4 $ — $ — $ 1,123.7
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, 2019 Customer relationships, beginning of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Amortization expense — (61.9 ) (61.9 ) Customer relationships, end of period $ 1,795.8 $ (484.1 ) $ 1,311.7
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2019 (remaining) $ 61.8 2020 123.7 2021 123.7 2022 123.7 2023 123.6 Thereafter 755.2 Total $ 1,311.7

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Assets and Liabilities, Lessee	Lease balances are recorded on the consolidated balance sheets as follows (in millions): June 30, 2019 Finance leases: Property and equipment $ 5.2 Accumulated depreciation (3.0 ) Property and equipment, net of accumulated depreciation $ 2.2 Other current liabilities $ 0.4 Operating leases: Other assets, net $ 83.2 Other current liabilities $ 21.7 Other long-term liabilities $ 84.3 Other lease information Weighted-average remaining lease term - Finance leases 0.3 years Weighted-average remaining lease term - Operating leases 10.7 years Weighted-average discount rate - Finance leases 9.3 % Weighted-average discount rate - Operating leases 5.2 %
Lease, Cost	Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Finance lease expense: Amortization of right-of-use asset $ 2.3 $ 3.0 Operating lease expense: Long-term operating lease expense 8.3 14.6 Short-term lease expense 8.9 15.8 Variable lease expense 1.4 3.0 Total lease expense $ 20.9 $ 36.4 Other information about our leases are as follows (dollar amounts in millions, lease terms in years): Three Months Ended June 30, Six Months Ended June 30, 2019 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 0.4 $ 0.8 Cash payments for operating leases included in cash flows from operating activities $ 8.2 $ 15.4 Right-of-use assets obtained in exchange for operating lease liabilities $ 14.6 $ 95.2
Lessee, Operating Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of June 30, 2019 (in millions): Total 2019 (remaining) 2020 2021 2022 2023 Thereafter Undiscounted finance lease liability $ 0.4 $ 0.4 $ — $ — $ — $ — $ — Finance lease liability 0.4 0.4 — — — — — Undiscounted operating lease liability 146.5 13.5 22.4 16.1 9.4 8.9 76.2 Reduction due to present value (40.5 ) (2.6 ) (4.5 ) (3.8 ) (3.4 ) (3.1 ) (23.1 ) Operating lease liability 106.0 10.9 17.9 12.3 6.0 5.8 53.1 Total lease liability $ 106.4 $ 11.3 $ 17.9 $ 12.3 $ 6.0 $ 5.8 $ 53.1
Finance Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of June 30, 2019 (in millions): Total 2019 (remaining) 2020 2021 2022 2023 Thereafter Undiscounted finance lease liability $ 0.4 $ 0.4 $ — $ — $ — $ — $ — Finance lease liability 0.4 0.4 — — — — — Undiscounted operating lease liability 146.5 13.5 22.4 16.1 9.4 8.9 76.2 Reduction due to present value (40.5 ) (2.6 ) (4.5 ) (3.8 ) (3.4 ) (3.1 ) (23.1 ) Operating lease liability 106.0 10.9 17.9 12.3 6.0 5.8 53.1 Total lease liability $ 106.4 $ 11.3 $ 17.9 $ 12.3 $ 6.0 $ 5.8 $ 53.1

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Summary of Debt	As of June 30, 2019 and December 31, 2018 , long-term debt consisted of the following (in millions): June 30, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt ENLC Credit Facility, due 2019 (1) $ — $ — $ — $ 111.4 $ — $ 111.4 Consolidated Credit Facility due 2024 (2) 200.0 — 200.0 — — — Term Loan due 2021 (3) 850.0 — 850.0 850.0 — 850.0 ENLK's 2.70% Senior unsecured notes due 2019 (4) — — — 400.0 — 400.0 ENLK’s 4.40% Senior unsecured notes due 2024 550.0 1.6 551.6 550.0 1.8 551.8 ENLK’s 4.15% Senior unsecured notes due 2025 750.0 (0.8 ) 749.2 750.0 (0.9 ) 749.1 ENLK’s 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.5 ) 499.5 ENLC’s 5.375% Senior unsecured notes due 2029 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 (6.1 ) 443.9 450.0 (6.2 ) 443.8 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 500.0 (0.1 ) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,650.0 $ (6.1 ) 4,643.9 $ 4,461.4 $ (6.1 ) 4,455.3 Debt issuance cost (5) (31.4 ) (24.5 ) Less: Current maturities of long-term debt (4) — (399.8 ) Long-term debt, net of unamortized issuance cost $ 4,612.5 $ 4,031.0 ____________________________ (1) Bore interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.4% at December 31, 2018 . In connection with the closing of the Merger, the ENLC Credit Facility was canceled, and all outstanding borrowings were refinanced through borrowings on the Consolidated Credit Facility. Since the borrowings under the ENLC Credit Facility were refinanced with long-term debt, they are classified as “Long-term debt” on the consolidated balance sheet as of December 31, 2018. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.0% at June 30, 2019 . (3) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% and 3.9% at June 30, 2019 and December 31, 2018 , respectively. (4) ENLK’s 2.70% senior unsecured notes matured on April 1, 2019. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of December 31, 2018 . (5) Net of amortization of $11.9 million and $16.5 million at June 30, 2019 and December 31, 2018 , respectively.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (provision) are as follows (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Current income tax benefit (provision) $ (0.3 ) $ 0.3 $ (1.3 ) $ (0.9 ) Deferred income tax benefit (provision) 5.7 (6.6 ) 4.9 (12.4 ) Income tax benefit (provision) $ 5.4 $ (6.3 ) $ 3.6 $ (13.3 )
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles total income tax benefit (provision) and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Expected income tax benefit (provision) based on federal statutory rate $ 4.5 $ (7.2 ) $ 41.2 $ (11.3 ) State income tax benefit (provision), net of federal benefit 0.4 (0.4 ) 4.3 (1.7 ) Non-deductible expense related to asset impairment — — (43.8 ) — Other 0.5 1.3 1.9 (0.3 ) Income tax benefit (provision) $ 5.4 $ (6.3 ) $ 3.6 $ (13.3 )
Schedule of Deferred Tax Assets and Liabilities	Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax assets, net of deferred tax liabilities, are included in “Other assets, net” in the consolidated balance sheets at June 30, 2019. Our deferred income tax assets and liabilities as of June 30, 2019 and December 31, 2018 are as follows (in millions): June 30, 2019 December 31, 2018 Deferred income tax assets: Federal net operating loss carryforward $ 106.2 $ 67.9 State net operating loss carryforward 16.6 11.7 Total deferred tax assets 122.8 79.6 Deferred tax liabilities: Property, equipment, and intangible assets (1) (78.2 ) (440.6 ) Other (0.1 ) (1.4 ) Total deferred tax liabilities (78.3 ) (442.0 ) Deferred tax asset (liability), net $ 44.5 $ (362.4 ) ____________________________ (1) Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment .

Certain Provisions of the Par_2

Certain Provisions of the Partnership Agreement (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 and 2018 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 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 2018 Fourth Quarter of 2017 413,658 $ 16.0 February 13, 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 A summary of ENLK’s distribution activity relating to the common units for periods prior to the Merger is provided below: Declaration period Distribution/unit Date paid/payable 2019 Fourth Quarter of 2018 $ 0.39 February 13, 2019 2018 Fourth Quarter of 2017 $ 0.39 February 13, 2018 First Quarter of 2018 $ 0.39 May 14, 2018 Second Quarter of 2018 $ 0.39 August 13, 2018
Incentive Distributions	For the three and six months ended June 30, 2018, the General Partner’s share of net income consisted of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner . The net income allocated to the General Partner is as follows (in millions): Three Months Ended Six Months Ended 2019 2018 2019 2018 Income allocation for incentive distributions $ — $ 14.8 $ — $ 29.6 Unit-based compensation attributable to ENLC’s restricted and performance units (6.4 ) (4.0 ) (18.5 ) (8.4 ) General Partner share of net income (loss) (0.2 ) 0.4 0.2 0.6 General Partner interest in EOGP acquisition — 12.6 2.4 16.8 General Partner interest in net income (loss) $ (6.6 ) $ 23.8 $ (15.9 ) $ 38.6

Members' Equity (Tables)

Members' Equity (Tables)	6 Months Ended
	Jun. 30, 2019
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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Distributed earnings allocated to: Common units (1)(2) $ 137.8 $ 48.3 $ 247.2 $ 95.9 Unvested restricted units (1)(2) 1.8 0.8 3.0 1.3 Total distributed earnings $ 139.6 $ 49.1 $ 250.2 $ 97.2 Undistributed loss allocated to: Common units $ (153.5 ) $ (20.8 ) $ (437.3 ) $ (56.1 ) Unvested restricted units (2.2 ) (0.3 ) (5.3 ) (0.7 ) Total undistributed loss $ (155.7 ) $ (21.1 ) $ (442.6 ) $ (56.8 ) Net income (loss) allocated to: Common units $ (15.7 ) $ 27.5 $ (190.1 ) $ 39.8 Unvested restricted units (0.4 ) 0.5 (2.3 ) 0.6 Total net income (loss) $ (16.1 ) $ 28.0 $ (192.4 ) $ 40.4 Basic and diluted net income (loss) per unit: Basic $ (0.03 ) $ 0.15 $ (0.44 ) $ 0.22 Diluted $ (0.03 ) $ 0.15 $ (0.44 ) $ 0.22 ____________________________ (1) For the three months ended June 30, 2019 and 2018 , distributed earnings represent a declared distribution of $0.283 per unit payable on August 13, 2019 and a distribution of $0.267 per unit paid on August 14, 2018 , respectively. (2) For the six months ended June 30, 2019 , distributed earnings included a distribution of $0.279 per unit paid on May 14, 2019 and a declared distribution of $0.283 per unit payable on August 13, 2019 . For the six months ended June 30, 2018 , distributed earnings included distributions of $0.263 per unit paid on May 15, 2018 and $0.267 per unit paid on August 14, 2018 .
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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Basic weighted average units outstanding: Weighted average common units outstanding 487.2 181.0 439.9 181.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 487.2 181.0 439.9 181.0 Dilutive effect of non-vested restricted units (1) — 1.2 — 1.0 Total weighted average diluted common units outstanding 487.2 182.2 439.9 182.0 ___________________________ (1) All common unit equivalents were antidilutive 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, 2019 and 2018 , respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2019 Fourth Quarter of 2018 $ 0.275 February 14, 2019 First Quarter of 2019 $ 0.279 May 14, 2019 Second Quarter 2019 $ 0.283 August 13, 2019 2018 Fourth Quarter of 2017 $ 0.259 February 14, 2018 First Quarter of 2018 $ 0.263 May 15, 2018 Second Quarter 2018 $ 0.267 August 14, 2018

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2019
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 2019 2018 2019 2018 GCF Distributions $ 7.4 $ 5.4 $ 9.6 $ 11.1 Equity in income $ 5.2 $ 4.8 $ 10.9 $ 9.4 Cedar Cove JV Contributions $ — $ 0.1 $ — $ 0.1 Distributions $ 0.2 $ — $ 0.5 $ 0.3 Equity in loss $ (0.5 ) $ (0.4 ) $ (0.9 ) $ (2.0 ) Total Contributions $ — $ 0.1 $ — $ 0.1 Distributions $ 7.6 $ 5.4 $ 10.1 $ 11.4 Equity in income $ 4.7 $ 4.4 $ 10.0 $ 7.4 The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2019 and December 31, 2018 (in millions): June 30, 2019 December 31, 2018 GCF $ 43.2 $ 41.9 Cedar Cove JV 36.8 38.2 Total investment in unconsolidated affiliates $ 80.0 $ 80.1

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 2019
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 June 30, Six Months Ended 2019 2018 2019 2018 Cost of unit-based compensation charged to operating expense $ 2.1 $ 2.3 $ 2.4 $ 4.3 Cost of unit-based compensation charged to general and administrative expense 5.9 7.3 16.7 10.4 Total unit-based compensation expense $ 8.0 $ 9.6 $ 19.1 $ 14.7 Non-controlling interest in unit-based compensation $ — $ 3.6 $ 0.5 $ 5.5 Amount of related income tax benefit recognized in net income $ 1.9 $ 1.2 $ 4.4 $ 1.9
Summary of Restricted Incentive Unit Activity	ENLC restricted incentive units are 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, 2019 is provided below: Six Months Ended EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,425,867 $ 14.62 Granted (1) 1,835,494 11.44 Vested (1)(2) (1,255,211 ) 10.47 Forfeited (272,185 ) 10.86 Converted from ENLK (3) 2,103,266 14.01 Non-vested, end of period 4,837,231 $ 14.44 Aggregate intrinsic value, end of period (in millions) $ 48.8 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2019, ENLC granted 420,842 restricted incentive units with a fair value of $4.8 million to officers and certain employees as bonus payments for 2018, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 420,778 units withheld for payroll taxes paid on behalf of employees. (3) Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. ENLK restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLK common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2019 is provided below: Six Months Ended EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,556,270 $ 14.43 Vested (1) (722,853 ) 10.02 Forfeited (4,490 ) 11.93 Converted to ENLC (2) (1,828,927 ) 16.11 Non-vested, end of period — $ — ____________________________ (1) Vested units included 249,201 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
Summary of Restricted Units' Aggregate Intrinsic Value	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2019 and 2018 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 under the GP Plan. Three Months Ended June 30, Six Months Ended June 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2019 2018 2019 2018 Aggregate intrinsic value of units vested $ — $ 0.4 $ 8.0 $ 9.1 Fair value of units vested $ — $ 0.5 $ 7.2 $ 13.3 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, 2019 and 2018 is provided below (in millions): Three Months Ended June 30, Six Months Ended June 30, EnLink Midstream, LLC Restricted Incentive Units: 2019 2018 2019 2018 Aggregate intrinsic value of units vested $ 0.5 $ 0.4 $ 12.9 $ 9.3 Fair value of units vested $ 0.5 $ 0.4 $ 13.1 $ 13.5
Summary of Performance Units	The following table presents a summary of the performance units: Six Months Ended EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 418,149 $ 19.15 Granted 931,469 13.02 Vested (1) (161,286 ) 11.71 Forfeited (92,422 ) 20.41 Converted from ENLK (2) 333,798 25.84 Non-vested, end of period 1,429,708 $ 17.48 Aggregate intrinsic value, end of period (in millions) $ 14.4 ____________________________ (1) Vested units included 62,219 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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 and 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2019 and 2018, respectively. Six Months Ended June 30, EnLink Midstream, LLC Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 1.8 $ 1.9 Fair value of units vested $ 1.9 $ 4.2 Six Months Ended EnLink Midstream Partners, LP Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 451,669 $ 17.74 Vested (1) (161,410 ) 10.54 Converted to ENLC (2) (290,259 ) 28.31 Non-vested, end of period — $ — ____________________________ (1) Vested units included 62,403 units withheld for payroll taxes paid on behalf of employees. (2) As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC unit-based performance awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. 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 and 2018 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 under the GP Plan. No performance units vested for the three months ended June 30, 2018. Six Months Ended June 30, EnLink Midstream Partners, LP Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 2.1 $ 2.0 Fair value of units vested $ 1.7 $ 4.1
Schedule of Performance Stock Vesting Levels	The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies: Performance Level Achieved ENLC TSR Position Relative to Designated Peer Companies Vesting percentage of the Tranche TSR Units Below Threshold Less than 25% 0% Threshold Equal to 25% 50% Target Equal to 50% 100% Maximum Greater than or Equal to 75% 200% Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. The following table sets out the levels at which the Tranche CF Units will be eligible to vest (using linear interpolation) based on the Cash Flow performance of ENLC for the performance period ending December 31, 2019: Performance Level ENLC’s Achieved Cash Flow Vesting percentage of the Tranche CF Units Below Threshold Less than $1.43 0% Threshold Equal to $1.43 50% Target Equal to $1.55 100% Maximum Greater than or Equal to $1.72 200%
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream, LLC Performance Units: June 2019 March 2019 Beginning TSR price $ 9.84 $ 10.92 Risk-free interest rate 1.72 % 2.42 % Volatility factor 33.50 % 33.86 % Distribution yield 11.5 % 9.7 %

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
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, 2019 December 31, 2018 Fair value of derivative assets—current $ 9.5 $ 28.6 Fair value of derivative assets—long-term 7.1 4.1 Fair value of derivative liabilities—current (2.5 ) (21.8 ) Fair value of derivative liabilities—long-term (0.4 ) (2.4 ) Net fair value of derivatives $ 13.7 $ 8.5 The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): June 30, 2019 Fair value of derivative liabilities—current $ (3.3 ) Fair value of derivative liabilities—long-term (10.2 ) Net fair value of derivatives $ (13.5 )
Components of Gain (Loss) on Derivative Activity	The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Change in fair value of derivatives $ 7.2 $ (10.5 ) $ 5.2 $ (14.0 ) Realized gain (loss) on derivatives (0.3 ) (4.7 ) 3.5 (0.7 ) Gain (loss) on derivative activity $ 6.9 $ (15.2 ) $ 8.7 $ (14.7 )
Notional Amount and Fair Value of Derivative Instruments	Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at June 30, 2019 (in millions). The remaining term of the contracts extend no later than December 2022. June 30, 2019 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (24.2 ) $ 3.0 NGL (long contracts) Swaps Gallons 15.0 (0.6 ) Natural gas (short contracts) Swaps MMBtu (2.4 ) 0.4 Natural gas (long contracts) Swaps MMBtu 6.3 (0.4 ) Crude and condensate (short contracts) Swaps MMbbls (12.3 ) 5.6 Crude and condensate (long contracts) Swaps MMbbls 0.8 5.7 Total fair value of derivatives $ 13.7

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Net assets measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2019 December 31, 2018 Interest rate swaps (1) $ (13.5 ) $ — Commodity swaps (2) $ 13.7 $ 8.5 ____________________________ (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, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 4,612.5 $ 4,480.4 $ 4,430.8 $ 4,065.0 Secured term loan receivable (2) $ — $ — $ 51.1 $ 51.1 ____________________________ (1) The carrying value of long-term debt as of December 31, 2018 includes current maturities. The carrying value of long-term debt is reduced by debt issuance costs of $31.4 million and $24.5 million at June 30, 2019 and December 31, 2018 , respectively. The respective fair values do not factor in debt issuance costs. (2) In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “ Note 2—Significant Accounting Policies .”

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2019
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, 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 Three Months Ended June 30, 2018 Natural gas sales $ 33.5 $ 23.3 $ 37.9 $ 122.7 $ — $ 217.4 NGL sales 0.3 — 3.6 627.9 — 631.8 Crude oil and condensate sales 511.5 — 23.3 51.1 — 585.9 Product sales 545.3 23.3 64.8 801.7 — 1,435.1 Natural gas sales—related parties — — 1.9 — — 1.9 NGL sales—related parties 122.9 11.5 140.4 28.9 (278.7 ) 25.0 Crude oil and condensate sales—related parties 0.4 0.4 0.3 0.1 (0.9 ) 0.3 Product sales—related parties 123.3 11.9 142.6 29.0 (279.6 ) 27.2 Gathering and transportation 7.6 6.8 25.6 16.7 — 56.7 Processing 7.3 2.2 47.4 1.1 — 58.0 NGL services — — — 10.3 — 10.3 Crude services 0.1 — — 14.9 — 15.0 Other services 2.0 — (0.1 ) 0.5 — 2.4 Midstream services 17.0 9.0 72.9 43.5 — 142.4 Gathering and transportation—related parties — 61.4 38.7 — — 100.1 Processing—related parties — 46.8 23.1 — — 69.9 Crude services—related parties 4.3 — 0.7 — — 5.0 Other services—related parties — 0.4 (0.2 ) — — 0.2 Midstream services—related parties 4.3 108.6 62.3 — — 175.2 Revenue from contracts with customers 689.9 152.8 342.6 874.2 (279.6 ) 1,779.9 Cost of sales (633.9 ) (32.0 ) (170.1 ) (769.2 ) 279.6 (1,325.6 ) Operating expenses (24.7 ) (28.4 ) (20.8 ) (39.5 ) — (113.4 ) Loss on derivative activity — — — — (15.2 ) (15.2 ) Segment profit $ 31.3 $ 92.4 $ 151.7 $ 65.5 $ (15.2 ) $ 325.7 Depreciation and amortization $ (27.3 ) $ (31.6 ) $ (46.4 ) $ (37.4 ) $ (2.6 ) $ (145.3 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 52.8 $ 5.5 $ 140.0 $ 18.8 $ 1.1 $ 218.2 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 Permian North Texas Oklahoma Louisiana Corporate Totals Six Months Ended June 30, 2018 Natural gas sales $ 71.2 $ 68.6 $ 86.0 $ 247.7 $ — $ 473.5 NGL sales 0.8 — 5.5 1,236.3 — 1,242.6 Crude oil and condensate sales 1,088.7 — 45.2 84.3 — 1,218.2 Product sales 1,160.7 68.6 136.7 1,568.3 — 2,934.3 Natural gas sales—related parties — — 2.4 — — 2.4 NGL sales—related parties 206.8 20.5 240.5 34.5 (474.9 ) 27.4 Crude oil and condensate sales—related parties 1.9 0.8 0.7 0.2 (2.6 ) 1.0 Product sales—related parties 208.7 21.3 243.6 34.7 (477.5 ) 30.8 Gathering and transportation 13.8 14.6 41.2 34.3 — 103.9 Processing 11.1 2.2 56.4 1.7 — 71.4 NGL services — — — 26.9 — 26.9 Crude services 0.1 — 0.1 27.7 — 27.9 Other services 3.7 0.3 — 0.5 — 4.5 Midstream services 28.7 17.1 97.7 91.1 — 234.6 Gathering and transportation—related parties — 114.0 73.4 — — 187.4 Processing—related parties — 98.4 45.2 — — 143.6 Crude services—related parties 8.6 — 1.4 — — 10.0 Other services—related parties — 0.4 — — — 0.4 Midstream services—related parties 8.6 212.8 120.0 — — 341.4 Revenue from contracts with customers 1,406.7 319.8 598.0 1,694.1 (477.5 ) 3,541.1 Cost of sales (1,308.0 ) (81.9 ) (309.4 ) (1,485.3 ) 477.5 (2,707.1 ) Operating expenses (48.5 ) (56.8 ) (41.5 ) (75.8 ) — (222.6 ) Loss on derivative activity — — — — (14.7 ) (14.7 ) Segment profit $ 50.2 $ 181.1 $ 247.1 $ 133.0 $ (14.7 ) $ 596.7 Depreciation and amortization $ (54.1 ) $ (62.9 ) $ (88.5 ) $ (73.3 ) $ (4.6 ) $ (283.4 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 116.4 $ 8.0 $ 243.9 $ 28.8 $ 2.3 $ 399.4
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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 Segment profit $ 292.0 $ 325.7 $ 593.3 $ 596.7 General and administrative expenses (32.2 ) (30.4 ) (83.6 ) (57.9 ) Loss on disposition of assets (0.1 ) (1.2 ) (0.1 ) (1.3 ) Depreciation and amortization (153.7 ) (145.3 ) (305.8 ) (283.4 ) Impairments — — (186.5 ) — Loss on secured term loan receivable (52.9 ) — (52.9 ) — Operating income (loss) $ 53.1 $ 148.8 $ (35.6 ) $ 254.1
Schedule of Segment Assets	The table below represents information about segment assets as of June 30, 2019 and December 31, 2018 (in millions): Segment Identifiable Assets: June 30, 2019 December 31, 2018 Permian $ 2,386.1 $ 2,096.8 North Texas 1,346.7 1,308.2 Oklahoma 3,881.7 3,209.5 Louisiana 2,575.1 2,734.5 Corporate 203.4 1,345.1 Total identifiable assets $ 10,393.0 $ 10,694.1

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 2019
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): Natural gas and NGLs inventory, prepaid expenses, and other: June 30, 2019 December 31, 2018 Natural gas and NGLs inventory $ 51.5 $ 41.3 Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1) — 19.4 Prepaid expenses and other 21.3 13.5 Natural gas and NGLs inventory, prepaid expenses, and other $ 72.8 $ 74.2 ____________________________ (1) In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “ Note 2—Significant Accounting Policies .” Other current liabilities: June 30, 2019 December 31, 2018 Accrued interest $ 41.1 $ 37.5 Accrued wages and benefits, including taxes 18.6 37.2 Accrued ad valorem taxes 25.8 28.1 Capital expenditure accruals 44.9 50.6 Onerous performance obligations — 9.0 Short-term lease liability 22.1 1.5 Suspense producer payments 15.4 34.6 Deferred revenue 48.6 6.6 Other 27.0 43.1 Other current liabilities $ 243.5 $ 248.2

General (Details)

General (Details) $ in Millions	Jan. 31, 2019shares	Jan. 25, 2019USD ($)shares	Jun. 30, 2019USD ($)
Related Party Transaction [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares		304,822,035
Goodwill, impairment loss | $			$ 186.5
EnLink Midstream Partners, LP
Related Party Transaction [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares	55,827,221
Common units conversion ratio			1.15
EnLink Oklahoma T.O.
Related Party Transaction [Line Items]
Noncontrolling interest, ownership percentage by parent	16.10%
Merger Agreement
Related Party Transaction [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares		304,822,035
Common units conversion ratio		1.15
Goodwill, impairment loss | $		$ 186.5
Increase (decrease) in deferred income taxes | $		$ 399

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Thousands	1 Months Ended			3 Months Ended		6 Months Ended
	Oct. 31, 2019	May 31, 2019	May 31, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Loss on secured term loan receivable				$ 52,900	$ 0	$ 52,900	$ 0
Lease liability				106,000		106,000
Other assets, net				83,200		83,200
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Lease liability								$ 97,600
Other assets, net								75,300
Other liabilities								$ 22,600
White Star
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Financing receivable, after allowance for credit loss		$ 58,000
Financing receivable, scheduled payment		$ 9,750	$ 19,500
Forecast | White Star
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Financing receivable, scheduled payment	$ 10,750
Minimum Volume Contract
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability				36,200		74,700
Contracts with customers, revenue recognition				$ 3,900		$ 7,700

Significant Accounting Polici_4

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Jun. 30, 2019USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 849.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 122
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 243.9
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]: 2021-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 92.9
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	$ 82.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 79.9
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	$ 228.1
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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Finite-Lived Intangible Assets [Line Items]
Goodwill, impairment loss			$ 186.5
Amortization expense	$ 31	$ 30.9	$ 61.9	$ 61.7
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			5 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 - Schedule of Goodwill (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
Goodwill [Roll Forward]
Goodwill, beginning of period	$ 1,310.2
Goodwill allocation	0
Impairment	(186.5)
Goodwill, end of period	1,123.7
Operating Segments | Permian
Goodwill [Roll Forward]
Goodwill, beginning of period	0
Goodwill allocation	184.6
Impairment	0
Goodwill, end of period	184.6
Operating Segments | North Texas
Goodwill [Roll Forward]
Goodwill, beginning of period	0
Goodwill allocation	125.7
Impairment	0
Goodwill, end of period	125.7
Operating Segments | Oklahoma
Goodwill [Roll Forward]
Goodwill, beginning of period	190.3
Goodwill allocation	623.1
Impairment	0
Goodwill, end of period	813.4
Operating Segments | Louisiana
Goodwill [Roll Forward]
Goodwill, beginning of period	0
Goodwill allocation	186.5
Impairment	(186.5)
Goodwill, end of period	0
Corporate
Goodwill [Roll Forward]
Goodwill, beginning of period	1,119.9
Goodwill allocation	(1,119.9)
Impairment	0
Goodwill, end of period	$ 0

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance			$ (422.2)
Amortization expense	$ (31)	$ (30.9)	(61.9)	$ (61.7)
Accumulated Amortization, Ending Balance	(484.1)		(484.1)
Net Carrying Amount, Ending Balance	1,311.7		1,311.7
Customer relationships
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			1,795.8
Accumulated Amortization, Beginning Balance			(422.2)
Net Carrying Amount, Beginning Balance			1,373.6
Amortization expense			(61.9)
Gross Carrying Amount, Ending Balance	1,795.8		1,795.8
Accumulated Amortization, Ending Balance	(484.1)		(484.1)
Net Carrying Amount, Ending Balance	$ 1,311.7		$ 1,311.7

Goodwill and Intangible Asset_5

Goodwill and Intangible Assets - Amortization Expense (Details) $ in Millions	Jun. 30, 2019USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2019 (remaining)	$ 61.8
2020	123.7
2021	123.7
2022	123.7
2023	123.6
Thereafter	755.2
Total	$ 1,311.7

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)

Jan. 31, 2019

Jan. 25, 2019

Jul. 18, 2018

Jun. 30, 2019

Jun. 30, 2018

Mar. 31, 2018

Jun. 30, 2019

Jun. 30, 2018

Dec. 31, 2018

Related Party Transaction [Line Items]

Business acquisition, equity interest issued or issuable, number of shares (in shares)

304,822,035

Cost of sales

$ 1,300,100,000

[1]

$ 1,325,600,000

[1]

$ 1,325,600,000

$ 2,663,500,000

[1]

$ 2,707,100,000

[1]

Accounts payable to related party

2,000,000

2,000,000

$ 4,300,000

Devon Energy Corporation | Customer Concentration Risk | Sales Revenue, Net

Related Party Transaction [Line Items]

Concentration risk

11.50%

10.60%

Cedar Cove Joint Venture

Related Party Transaction [Line Items]

Cost of sales

5,800,000

$ 9,500,000

13,900,000

$ 22,500,000

Accounts receivable balance

0

0

700,000

Accounts payable to related party

$ 2,000,000

$ 2,000,000

$ 4,300,000

EnLink Oklahoma T.O.

Related Party Transaction [Line Items]

Noncontrolling interest, ownership percentage by parent

16.10%

EnLink Oklahoma T.O. | ENLC

Related Party Transaction [Line Items]

Noncontrolling interest, ownership percentage by parent

16.10%

ENLC

Related Party Transaction [Line Items]

Business acquisition, equity interest issued or issuable, number of shares (in shares)

55,827,221

GIP | Devon Energy Corporation

Related Party Transaction [Line Items]

Consideration

$ 3,125,000,000

[1]

$5.8 million and $46.7 million for the three months ended June 30, 2019 and 2018 , respectively, and

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	Jun. 30, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lease liability	$ 106
Right-of-use assets	83.2
Office Lease
Lessee, Lease, Description [Line Items]
Lease liability	62.5
Right-of-use assets	41.5
Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Lease liability	28.2
Right-of-use assets	30.1
Office Equipment
Lessee, Lease, Description [Line Items]
Lease liability	0.7
Right-of-use assets	0.7
Land
Lessee, Lease, Description [Line Items]
Lease liability	15
Right-of-use assets	$ 13.1

Leases - Lease Balances on Cons

Leases - Lease Balances on Consolidated Balance Sheet (Details) $ in Millions	Jun. 30, 2019USD ($)
Finance leases:
Property and equipment	$ 5.2
Accumulated depreciation	(3)
Property and equipment, net of accumulated depreciation	2.2
Other current liabilities	0.4
Operating leases:
Other assets, net	83.2
Other current liabilities	21.7
Other long-term liabilities	$ 84.3
Other Lease Information [Abstract]
Weighted-average remaining lease term - Finance leases	3 months 18 days
Weighted-average remaining lease term - Operating leases	10 years 8 months 12 days
Weighted-average discount rate - Finance leases	9.30%
Weighted-average discount rate - Operating leases	5.20%

Leases - Components of Total Le

Leases - Components of Total Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Finance lease expense:
Amortization of right-of-use asset	$ 2.3	$ 3
Operating lease expense:
Long-term operating lease expense	8.3	14.6
Short-term lease expense	8.9	15.8
Variable lease expense	1.4	3
Total lease expense	$ 20.9	$ 36.4

Leases - Other Information (Det

Leases - Other Information (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Supplemental disclosures of cash flow information:
Cash payments for finance leases included in cash flows from financing activities	$ 0.4	$ 0.8
Cash payments for operating leases included in cash flows from operating activities	8.2	15.4
Right-of-use assets obtained in exchange for operating lease liabilities	$ 14.6	$ 95.2

Leases - Maturity (Details)

Leases - Maturity (Details) $ in Millions	Jun. 30, 2019USD ($)
Undiscounted finance lease liability
Total	$ 0.4
2019 (remaining)	0.4
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Finance lease liability
Total	0.4
2019 (remaining)	0.4
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Undiscounted operating lease liability
Total	146.5
2019 (remaining)	13.5
2020	22.4
2021	16.1
2022	9.4
2023	8.9
Thereafter	76.2
Reduction due to present value
Total	(40.5)
2019 (remaining)	(2.6)
2020	(4.5)
2021	(3.8)
2022	(3.4)
2023	(3.1)
Thereafter	(23.1)
Operating Lease Liability [Abstract]
Total	106
2019 (remaining)	10.9
2020	17.9
2021	12.3
2022	6
2023	5.8
Thereafter	53.1
Total lease liability, Total	106.4
Total lease liability, 2019 (remaining)	11.3
Total lease liability, 2020	17.9
Total lease liability, 2021	12.3
Total lease liability, 2022	6
Total lease liability, 2023	5.8
Total lease liability, Thereafter	$ 53.1

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument
Outstanding Principal	$ 4,650	$ 4,461.4
Premium (Discount)	(6.1)	(6.1)
Long-Term Debt	4,643.9	4,455.3
Debt issuance costs	(31.4)	(24.5)
Less: Current maturities of long-term debt	0	(399.8)
Long-term debt, net of unamortized issuance cost	4,612.5	4,031
Debt issuance cost accumulated amortization	11.9	16.5
ENLC credit facility due 2019
Debt Instrument
Outstanding Principal	0	111.4
Premium (Discount)	0	0
Long-Term Debt	0	$ 111.4
Effective interest rate		4.40%
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding Principal	200	$ 0
Premium (Discount)	0	0
Long-Term Debt	$ 200	0
Effective interest rate	4.00%
Term Loan Due 2021
Debt Instrument
Outstanding Principal	$ 850	850
Premium (Discount)	0	0
Long-Term Debt	$ 850	$ 850
Effective interest rate	3.90%	3.90%
ENLK’s 2.70% Senior unsecured notes due 2019
Debt Instrument
Stated interest rate		2.70%
Outstanding Principal	$ 0	$ 400
Premium (Discount)	0	0
Long-Term Debt	$ 0	400
ENLK’s 4.40% Senior unsecured notes due 2024
Debt Instrument
Stated interest rate	4.40%
Outstanding Principal	$ 550	550
Premium (Discount)	1.6	1.8
Long-Term Debt	$ 551.6	551.8
ENLK’s 4.15% Senior unsecured notes due 2025
Debt Instrument
Stated interest rate	4.15%
Outstanding Principal	$ 750	750
Premium (Discount)	(0.8)	(0.9)
Long-Term Debt	$ 749.2	749.1
ENLK’s 4.85% Senior unsecured notes due 2026
Debt Instrument
Stated interest rate	4.85%
Outstanding Principal	$ 500	500
Premium (Discount)	(0.5)	(0.5)
Long-Term Debt	$ 499.5	499.5
ENLC's 5.375 Senior unsecured notes due 2029
Debt Instrument
Stated interest rate	5.375%
Outstanding Principal	$ 500	0
Premium (Discount)	0	0
Long-Term Debt	$ 500	0
ENLK’s 5.60% Senior unsecured notes due 2044
Debt Instrument
Stated interest rate	5.375%
Outstanding Principal	$ 350	350
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
ENLK’s 5.05% Senior unsecured notes due 2045
Debt Instrument
Stated interest rate	5.05%
Outstanding Principal	$ 450	450
Premium (Discount)	(6.1)	(6.2)
Long-Term Debt	$ 443.9	443.8
ENLK’s 5.45% Senior unsecured notes due 2047
Debt Instrument
Stated interest rate	5.45%
Outstanding Principal	$ 500	500
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Apr. 09, 2019USD ($)	Dec. 11, 2018USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018
Debt Instrument
Proceeds from borrowings	$ 496,500,000		$ 2,320,000,000	$ 1,361,800,000
ENLC's 5.375 Senior unsecured notes due 2029
Debt Instrument
Stated interest rate			5.375%
ENLK’s 2.70% Senior unsecured notes due 2019
Debt Instrument
Face amount					$ 400,000,000
Stated interest rate						2.70%
Letters of credit
Debt Instrument
Additional amount available (not to exceed)		$ 1,750,000,000	$ 2,250,000,000
Line of credit facility, fair value of amount outstanding			$ 200,000,000
Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA		5
Maximum
Debt Instrument
Stated interest rate						5.60%
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
Minimum
Debt Instrument
Stated interest rate			4.15%			2.70%
Unsecured Debt | ENLC's 5.375 Senior unsecured notes due 2029
Debt Instrument
Face amount	$ 500,000,000
Stated interest rate	5.375%
Debt instrument, percentage price of debt issued	100.00%
Unsecured Debt | Letters of credit
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio		2.5
Ratio of consolidated indebtedness to consolidated EBITDA		5
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio		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 | Maximum | Letters of credit
Debt Instrument
Variable rate		2.00%
Unsecured Debt | LIBOR | Minimum | Letters of credit
Debt Instrument
Variable rate		1.125%
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 | Maximum | Letters of credit
Debt Instrument
Variable rate		1.00%
Unsecured Debt | Eurodollar | Minimum | Letters of credit
Debt Instrument
Variable rate		0.125%
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity		$ 500,000,000
Debt instrument, covenant, percentage of letter of credits guaranteed			105.00%
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 | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate		1.75%
Line of Credit | LIBOR | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate		1.00%
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 | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate		0.75%
Line of Credit | Eurodollar | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate		0.00%
ENLC | Letter of Credit | Letters of credit
Debt Instrument
Line of credit facility, fair value of amount outstanding			$ 5,000,000

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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Current income tax benefit (provision)	$ (0.3)	$ 0.3	$ (1.3)	$ (0.9)
Deferred income tax benefit (provision)	5.7	(6.6)	4.9	(12.4)
Income tax benefit (provision)	5.4	(6.3)	3.6	(13.3)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (provision) based on federal statutory rate	4.5	(7.2)	41.2	(11.3)
State income tax benefit (provision), net of federal benefit	0.4	(0.4)	4.3	(1.7)
Non-deductible expense related to asset impairment	0	0	(43.8)	0
Other	0.5	1.3	1.9	(0.3)
Income tax benefit (provision)	$ 5.4	$ (6.3)	$ 3.6	$ (13.3)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Deferred income tax assets:
Federal net operating loss carryforward	$ 106.2	$ 67.9
State net operating loss carryforward	16.6	11.7
Total deferred tax assets	122.8	79.6
Deferred tax liabilities:
Property, equipment, and intangible assets	(78.2)	(440.6)
Other	(0.1)	(1.4)
Total deferred tax liabilities	(78.3)	(442)
Deferred tax asset (liability), net	$ 44.5
Deferred tax asset (liability), net		$ (362.4)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Jun. 30, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Issuance of common units for ENLK public common units related to the Merger	$ 399	$ 0.9
Operating loss carryforwards			$ 505.5	$ 323.6
Deferred tax assets, federal net operating loss carryforwards			$ 106.2	$ 67.9

Certain Provisions of the Par_3

Certain Provisions of the Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 24, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Jun. 30, 2019
Partnership agreement
Distribution declared/unit (in dollars per share)		$ 0.283	$ 0.279	$ 0.275	$ 0.267	$ 0.263	$ 0.259	$ 0.283
General Partner | Incentive Distribution Level 1
Partnership agreement
Incentive distribution for general partner	13.00%
Incentive distribution, conditional distribution per unit (in dollars per share)	$ 0.25
General Partner | Incentive Distribution Level 2
Partnership agreement
Incentive distribution for general partner	23.00%
Incentive distribution, conditional distribution per unit (in dollars per share)	$ 0.3125
General Partner | Incentive Distribution Level 3
Partnership agreement
Incentive distribution for general partner	48.00%
Incentive distribution, conditional distribution per unit (in dollars per share)	$ 0.375
EnLink Midstream Partners, LP
Partnership agreement
Common units conversion ratio								1.15
Series B Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)		148,257	147,887	425,785	419,678	416,657	413,658
Cash distributions		$ 17.1	$ 16.7	$ 16.5	$ 16.3	$ 16.2	$ 16
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Annual rate on issue price								0.25%
Common units conversion ratio								1.15
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners capital account, redemption price (in usd per share)								$ 1,000
Partners' capital account, distributions		$ 12
Common units | EnLink Midstream Partners, LP
Partnership agreement
Distribution declared/unit (in dollars per share)				$ 0.39	$ 0.39	$ 0.39	$ 0.39
Limited Partner | Series B Preferred Unitholders
Partnership agreement
Distribution declared/unit (in dollars per share)	$ 0.28125
Annual rate on issue price payable in kind	0.25%
Shares issued, price per share (in dollars per share)	$ 15
Limited Partner | Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, dividend rate, percentage								6.00%
LIBOR | Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, distributions, variable floating rate percentage								4.11%

Certain Provisions of the Par_4

Certain Provisions of the Partnership Agreement - Allocation of Income (Details) - General Partner - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Incentive distribution
Income allocation for incentive distributions	$ 0	$ 14.8	$ 0	$ 29.6
Unit-based compensation attributable to ENLC’s restricted and performance units	(6.4)	(4)	(18.5)	(8.4)
General Partner share of net income (loss)	(0.2)	0.4	0.2	0.6
General Partner interest in EOGP acquisition	0	12.6	2.4	16.8
General Partner interest in net income (loss)	$ (6.6)	$ 23.8	$ (15.9)	$ 38.6

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	May 14, 2019	Feb. 22, 2019	Jan. 25, 2019	Aug. 14, 2018	May 15, 2018	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares)			304,822,035
ENLC interest in net income		$ 400
Distributed earnings allocated to:
Total distributed earnings						$ 139.6			$ 49.1			$ 250.2	$ 97.2
Undistributed loss allocated to:
Total undistributed loss						(155.7)			(21.1)			(442.6)	(56.8)
Net income (loss) allocated to:
Total net income (loss)						$ (16.1)			$ 28			$ (192.4)	$ 40.4
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)						$ (0.03)			$ 0.15			$ (0.44)	$ 0.22
Diluted (in dollars per share)						(0.03)			0.15			(0.44)	$ 0.22
Distribution declared/unit (in dollars per share)						$ 0.283	$ 0.279	$ 0.275	$ 0.267	$ 0.263	$ 0.259	$ 0.283
Distribution paid per unit (in dollars per share)	$ 0.279			$ 0.267	$ 0.263
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings						$ 1.8			$ 0.8			$ 3	$ 1.3
Undistributed loss allocated to:
Total undistributed loss						(2.2)			(0.3)			(5.3)	(0.7)
Net income (loss) allocated to:
Total net income (loss)						(0.4)			0.5			(2.3)	0.6
Common units
Distributed earnings allocated to:
Total distributed earnings						137.8			48.3			247.2	95.9
Undistributed loss allocated to:
Total undistributed loss						(153.5)			(20.8)			(437.3)	(56.1)
Net income (loss) allocated to:
Total net income (loss)						$ (15.7)			$ 27.5			$ (190.1)	$ 39.8

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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Basic weighted average units outstanding:
Weighted average common units outstanding (in shares)	487.2	181	439.9	181
Diluted weighted average units outstanding:
Weighted average basic common units outstanding (in shares)	487.2	181	439.9	181
Dilutive effect of non-vested restricted units (in shares)	0	1.2	0	1
Total weighted average diluted common units outstanding (in shares)	487.2	182.2	439.9	182

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Equity method investments
Contributions	$ 0	$ 0.1	$ 0	$ 0.1
Distributions	7.6	5.4	10.1	11.4
Equity in income (loss)	4.7	4.4	10	7.4
Total investment in unconsolidated affiliates	$ 80		$ 80		$ 80.1
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Distributions	$ 7.4	5.4	$ 9.6	11.1
Equity in income (loss)	$ 5.2	4.8	$ 10.9	9.4
Cedar Cove JV
Equity method investments
Ownership interest	30.00%		30.00%
Contributions	$ 0	0.1	$ 0	0.1
Distributions	0.2	0	0.5	0.3
Equity in income (loss)	(0.5)	$ (0.4)	(0.9)	$ (2)
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	80		80		80.1
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	43.2		43.2		41.9
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ 36.8		$ 36.8		$ 38.2

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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Allocation
Compensation expense	$ 8	$ 9.6	$ 19.1	$ 14.7
Amount of related income tax benefit recognized in net income	1.9	1.2	4.4	1.9
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	2.1	2.3	2.4	4.3
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	5.9	7.3	16.7	10.4
Non-controlling interest in unit-based compensation
Allocation
Compensation expense	$ 0	$ 3.6	$ 0.5	$ 5.5

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	Jul. 23, 2018	Mar. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price (in dollars per share)				$ 10.92			$ 9.84
Risk-free interest rate				2.42%			1.72%
Volatility factor				33.86%			33.50%
Distribution yield				9.70%			11.50%
EnLink Midstream Partners, LP
Weighted Average Grant-Date Fair Value
Common units conversion ratio							1.15
Unvested restricted units
Number of Units
Non-vested, beginning of period (in shares)				2,425,867			2,425,867
Granted (in shares)		420,842					1,835,494
Vested (in shares)							(1,255,211)
Forfeited (in shares)							(272,185)
Converted to ENLC (in shares)							2,103,266
Non-vested, end of period (in shares)			4,837,231				4,837,231
Aggregate intrinsic value, end of period			$ 48.8				$ 48.8
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 14.62			$ 14.62
Granted (in dollars per share)							11.44
Vested (in dollars per share)							10.47
Forfeited (in dollars per share)							10.86
Converted to ENLC (in dollars per share)							14.01
Non-vested, end of period (in dollars per share)			$ 14.44				$ 14.44
Units withheld for payroll taxes (in shares)							420,778
Fair value of units vested		$ 4.8
Unrecognized compensation cost related to non-vested restricted incentive units			$ 38.2				$ 38.2
Unrecognized compensation costs, weighted average period for recognition							1 year 10 months 24 days
Vesting period							3 years
Unvested restricted units | ENLC
Weighted Average Grant-Date Fair Value
Aggregate intrinsic value of units vested			0.5		$ 0.4		$ 12.9	$ 9.3
Fair value of units vested			$ 0.5		0.4		$ 13.1	13.5
Unvested restricted units | EnLink Midstream Partners, LP
Number of Units
Non-vested, beginning of period (in shares)				2,556,270			2,556,270
Vested (in shares)							(722,853)
Forfeited (in shares)							(4,490)
Converted to ENLC (in shares)							(1,828,927)
Non-vested, end of period (in shares)			0				0
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 14.43			$ 14.43
Vested (in dollars per share)							10.02
Forfeited (in dollars per share)							11.93
Converted to ENLC (in dollars per share)							16.11
Non-vested, end of period (in dollars per share)			$ 0				$ 0
Units withheld for payroll taxes (in shares)							249,201
Aggregate intrinsic value of units vested			$ 0		0.4		$ 8	9.1
Fair value of units vested			$ 0		$ 0.5		$ 7.2	$ 13.3
Performance units
Number of Units
Non-vested, beginning of period (in shares)				418,149			418,149
Granted (in shares)							931,469
Vested (in shares)							(161,286)
Forfeited (in shares)							(92,422)
Converted to ENLC (in shares)							333,798
Non-vested, end of period (in shares)			1,429,708				1,429,708
Aggregate intrinsic value, end of period			$ 14.4				$ 14.4
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 19.15			$ 19.15
Granted (in dollars per share)							13.02
Vested (in dollars per share)							11.71
Forfeited (in dollars per share)							20.41
Converted to ENLC (in dollars per share)							25.84
Non-vested, end of period (in dollars per share)			$ 17.48				$ 17.48
Units withheld for payroll taxes (in shares)							62,219
Aggregate intrinsic value of units vested				$ 1.8		$ 1.9
Fair value of units vested				$ 1.9		4.2
Unrecognized compensation cost related to non-vested restricted incentive units			$ 16.7				$ 16.7
Unrecognized compensation costs, weighted average period for recognition							2 years
Vesting period							3 years
Performance units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting	0.00%						0.00%
Performance units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting	100.00%						200.00%
Performance units | EnLink Midstream Partners, LP
Number of Units
Non-vested, beginning of period (in shares)				451,669			451,669
Vested (in shares)							(161,410)
Converted to ENLC (in shares)							(290,259)
Non-vested, end of period (in shares)			0				0
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 17.74			$ 17.74
Vested (in dollars per share)							10.54
Converted to ENLC (in dollars per share)							28.31
Non-vested, end of period (in dollars per share)			$ 0				$ 0
Units withheld for payroll taxes (in shares)							62,403
Aggregate intrinsic value of units vested				$ 2.1		2
Fair value of units vested				$ 1.7		$ 4.1
Compensation expense not yet recognized			$ 0.7				$ 0.7
Vesting period							3 years
Performance units | EnLink Midstream Partners, LP | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting							0.00%
Performance units | EnLink Midstream Partners, LP | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting							200.00%
ENLC Performance Shares
Weighted Average Grant-Date Fair Value
Compensation expense not yet recognized			$ 2.1				$ 2.1

Employee Incentive Plans - Perf

Employee Incentive Plans - Performance Unit Awards (Details)	Jun. 30, 2019$ / shares
Below Threshold | Performance units
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	0.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	25.00%
Below Threshold | Cash Flow Performance Unit
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	0.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	143.00%
Threshold | Performance units
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	50.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	25.00%
Threshold | Cash Flow Performance Unit
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	50.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	143.00%
Target | Performance units
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	100.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	50.00%
Target | Cash Flow Performance Unit
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	100.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	155.00%
Maximum | Performance units
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	200.00%
Achieved ENLC TSR Position Relative to Designated Peer Companies	75.00%
Maximum | Cash Flow Performance Unit
Incentive Plans [Line Items]
Vesting percentage of the Tranche TSR Units	200.00%
Share-based compensation arrangement by share-based payment award, performance target percentage, per share	$ 1.72

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($)		3 Months Ended			6 Months Ended
		Jun. 30, 2019		Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Apr. 30, 2019	Dec. 31, 2018	May 31, 2017
Derivatives
Derivative, notional amount							$ 850,000,000
Derivative, fixed interest rate							2.27825%
Accumulated other comprehensive loss		$ 11,900,000			$ 11,900,000			$ 2,000,000	$ 2,200,000
Loss on designated cash flow hedge	[1]	9,900,000	[2]	$ 0	9,900,000	$ 0
Gain on interest rate swaps		300,000			300,000
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months		(3,400,000)			(3,400,000)
Fair value of derivative liabilities—current		(5,800,000)			(5,800,000)			(21,800,000)
Fair value of derivative liabilities—long-term		(10,600,000)			(10,600,000)			$ (2,400,000)
Interest rate swaps
Derivatives
Fair value of derivative liabilities—current		(3,300,000)			(3,300,000)
Fair value of derivative liabilities—long-term		(10,200,000)			(10,200,000)
Net fair value of derivatives		$ (13,500,000)			$ (13,500,000)
[1]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2019 , respectively, and an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2018 , respectively.
[2]	Includes a tax benefit of $3.6 million and an immaterial amount of amortization to interest expense.

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivatives
Gain (loss) on derivative activity	$ 6.9	$ (15.2)	$ (15.2)	$ 8.7	$ (14.7)
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	7.2	(10.5)		5.2	(14)
Realized gain (loss) on derivatives	(0.3)	(4.7)		3.5	(0.7)
Gain (loss) on derivative activity	$ 6.9	$ (15.2)		$ 8.7	$ (14.7)

Derivatives - Fair Value of Ass

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivatives
Fair value of derivative assets—current	$ 9.5	$ 28.6
Fair value of derivative assets—long-term	7.1	4.1
Fair value of derivative liabilities—current	(5.8)	(21.8)
Fair value of derivative liabilities—long-term	(10.6)	(2.4)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	9.5	28.6
Fair value of derivative assets—long-term	7.1	4.1
Fair value of derivative liabilities—current	(2.5)	(21.8)
Fair value of derivative liabilities—long-term	(0.4)	(2.4)
Net fair value of derivatives	$ 13.7	$ 8.5

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, 2019USD ($)MMBTUgalMMBbls	Dec. 31, 2018USD ($)
Derivatives
Fair Value	$ 13.7	$ 8.5
Commodity
Derivatives
Fair Value	13.7
Maximum loss if counterparties fail to perform	16.6
Possible reduction in maximum loss if counterparties fail to perform	$ 13.8
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	24.2
Fair Value	$ 3
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	15
Fair Value	$ (0.6)
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	2.4
Fair Value	$ 0.4
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	6.3
Fair Value	$ (0.4)
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	12.3
Fair Value	$ 5.6
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	0.8
Fair Value	$ 5.7

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Interest rate swaps
Fair Value
Fair Value	$ (13.5)
Level 2 | Interest rate swaps | Recurring
Fair Value
Fair Value	(13.5)	$ 0
Level 2 | Commodity swaps | Recurring
Fair Value
Fair Value	$ 13.7	$ 8.5

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Jun. 30, 2019	May 31, 2019	Dec. 31, 2018
Fair Value
Debt issuance costs	$ 31,400,000		$ 24,500,000
Senior unsecured debt			$ 3,500,000,000
Minimum
Fair Value
Stated interest rate	4.15%		2.70%
Maximum
Fair Value
Stated interest rate			5.60%
Carrying Value
Fair Value
Long-term debt	$ 4,612,500,000		$ 4,430,800,000
Secured term loan receivable	0		51,100,000
Fair Value
Fair Value
Long-term debt	4,480,400,000		4,065,000,000
Secured term loan receivable	0		$ 51,100,000
EnLink Midstream Partners, LP
Fair Value
Senior unsecured debt	$ 3,600,000,000
Second Lien Secured Term Loan
Fair Value
Maximum borrowing capacity		$ 58,000,000

Segment Information - Narrative

Segment Information - Narrative (Details)	6 Months Ended
	Jun. 30, 2019segment
Segment Reporting [Abstract]
Number of segments	5

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	3 Months Ended					6 Months Ended
	Jun. 30, 2019		Jun. 30, 2018		Mar. 31, 2018	Jun. 30, 2019		Jun. 30, 2018		Dec. 31, 2018
Segment Reporting
Revenue from contracts with customers	$ 1,703.1				$ 1,779.9	$ 3,480.5		$ 3,541.1
Cost of sales	(1,300.1)	[1]	$ (1,325.6)	[1]	(1,325.6)	(2,663.5)	[1]	(2,707.1)	[1]
Operating expenses	(117.9)		(113.4)		(113.4)	(232.4)		(222.6)
Gain (loss) on derivative activity	6.9		(15.2)		(15.2)	8.7		(14.7)
Segment profit	292		325.7		325.7	593.3		596.7
Depreciation and amortization	(153.7)		(145.3)		(145.3)	(305.8)		(283.4)
Impairments	0		0			(186.5)		0
Goodwill	1,123.7		1,542.2		1,542.2	1,123.7		1,542.2		$ 1,310.2
Capital expenditures	171.6				218.2	422.6		399.4
Total identifiable assets	10,393					10,393				10,694.1
Corporate
Segment Reporting
Revenue from contracts with customers	(218.7)				(279.6)	(476)		(477.5)
Cost of sales	218.7				279.6	476		477.5
Operating expenses	0				0	0		0
Gain (loss) on derivative activity	6.9				(15.2)	8.7		(14.7)
Segment profit	6.9				(15.2)	8.7		(14.7)
Depreciation and amortization	(2.2)				(2.6)	(4.2)		(4.6)
Impairments						0
Goodwill	0		1,119.9		1,119.9	0		1,119.9		1,119.9
Capital expenditures	2.4				1.1	4		2.3
Total identifiable assets	203.4					203.4				1,345.1
Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	742.3				689.9	1,484.9		1,406.7
Cost of sales	(680.5)				(633.9)	(1,356.7)		(1,308)
Operating expenses	(28.4)				(24.7)	(56.2)		(48.5)
Gain (loss) on derivative activity	0				0	0		0
Segment profit	33.4				31.3	72		50.2
Depreciation and amortization	(30.1)				(27.3)	(58)		(54.1)
Impairments						0
Goodwill	184.6		29.3		29.3	184.6		29.3		0
Capital expenditures	52.4				52.8	148.3		116.4
Total identifiable assets	2,386.1					2,386.1				2,096.8
North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	149.8				152.8	324.1		319.8
Cost of sales	(51)				(32)	(124.7)		(81.9)
Operating expenses	(25.8)				(28.4)	(51.5)		(56.8)
Gain (loss) on derivative activity	0				0	0		0
Segment profit	73				92.4	147.9		181.1
Depreciation and amortization	(36.9)				(31.6)	(71.2)		(62.9)
Impairments						0
Goodwill	125.7		202.7		202.7	125.7		202.7		0
Capital expenditures	27				5.5	31.3		8
Total identifiable assets	1,346.7					1,346.7				1,308.2
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	299.2				342.6	618.9		598
Cost of sales	(159.4)				(170.1)	(343.6)		(309.4)
Operating expenses	(26.1)				(20.8)	(51.5)		(41.5)
Gain (loss) on derivative activity	0				0	0		0
Segment profit	113.7				151.7	223.8		247.1
Depreciation and amortization	(47.6)				(46.4)	(93.7)		(88.5)
Impairments						0
Goodwill	813.4		190.3		190.3	813.4		190.3		190.3
Capital expenditures	70.3				140	178.5		243.9
Total identifiable assets	3,881.7					3,881.7				3,209.5
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	730.5				874.2	1,528.6		1,694.1
Cost of sales	(627.9)				(769.2)	(1,314.5)		(1,485.3)
Operating expenses	(37.6)				(39.5)	(73.2)		(75.8)
Gain (loss) on derivative activity	0				0	0		0
Segment profit	65				65.5	140.9		133
Depreciation and amortization	(36.9)				(37.4)	(78.7)		(73.3)
Impairments						(186.5)
Goodwill	0		0		0	0		0		0
Capital expenditures	19.5				18.8	60.5		28.8
Total identifiable assets	2,575.1					2,575.1				$ 2,734.5
Product sales
Segment Reporting
Revenue from contracts with customers	1,450.4		1,435.1		1,435.1	2,981.3		2,934.3
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	631.8				545.3	1,248.5		1,160.7
Product sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	40.6				23.3	100.5		68.6
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	93.1				64.8	193.3		136.7
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	684.9				801.7	1,439		1,568.3
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers	193.8				217.4	464.3		473.5
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales, Natural gas sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	(1)				33.5	35.1		71.2
Product sales, Natural gas sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	31.9				23.3	82.5		68.6
Product sales, Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	60.3				37.9	121.9		86
Product sales, Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	102.6				122.7	224.8		247.7
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers	512.6				631.8	1,103.7		1,242.6
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales, NGL sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.8				0.3	0.6		0.8
Product sales, NGL sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	8.7				0	18		0
Product sales, NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	4.3				3.6	13.2		5.5
Product sales, NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	498.8				627.9	1,071.9		1,236.3
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	744.1				585.9	1,413.3		1,218.2
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales, Crude oil and condensate sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	632				511.5	1,212.8		1,088.7
Product sales, Crude oil and condensate sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales, Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	28.6				23.3	58.2		45.2
Product sales, Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	83.5				51.1	142.3		84.3
Product sales, Other
Segment Reporting
Revenue from contracts with customers	(0.1)
Product sales, Other | Corporate
Segment Reporting
Revenue from contracts with customers	0
Product sales, Other | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0
Product sales, Other | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0
Product sales, Other | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	(0.1)
Product sales, Other | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0		27.2		27.2	0		30.8
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(217.8)				(279.6)	(477.8)		(477.5)
Product sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	83.7				123.3	184.9		208.7
Product sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	24.2				11.9	53.7		21.3
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	104.6				142.6	230.7		243.6
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	5.3				29	8.5		34.7
Product sales, Natural gas sales, related party
Segment Reporting
Revenue from contracts with customers	0				1.9	0		2.4
Product sales, Natural gas sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(0.7)				0	(0.7)		0
Product sales, Natural gas sales, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.4				0	0.4		0
Product sales, Natural gas sales, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.3				0	0.3		0
Product sales, Natural gas sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				1.9	0		2.4
Product sales, Natural gas sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers	0				25	0		27.4
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(208.5)				(278.7)	(463.5)		(474.9)
Product sales, NGL sales, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	76.4				122.9	173.6		206.8
Product sales, NGL sales, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	22.2				11.5	50.7		20.5
Product sales, NGL sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	104.6				140.4	230.7		240.5
Product sales, NGL sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	5.3				28.9	8.5		34.5
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers	0				0.3	0		1
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(8.6)				(0.9)	(13.6)		(2.6)
Product sales, Crude oil and condensate sales, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	6.9				0.4	10.9		1.9
Product sales, Crude oil and condensate sales, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	1.7				0.4	2.7		0.8
Product sales, Crude oil and condensate sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0.3	0		0.7
Product sales, Crude oil and condensate sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0.1	0		0.2
Midstream services
Segment Reporting
Revenue from contracts with customers	252.7		142.4		142.4	499.2		234.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	26.8				17	51.5		28.7
Midstream services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	85				9	169.9		17.1
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	100.3				72.9	193.4		97.7
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	40.6				43.5	84.4		91.1
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers	136.2				56.7	282.6		103.9
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Gathering and transportation | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	11.3				7.6	21.6		13.8
Midstream services, Gathering and transportation | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	49				6.8	112.6		14.6
Midstream services, Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	59.2				25.6	114.5		41.2
Midstream services, Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	16.7				16.7	33.9		34.3
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers	79.5				58	143.3		71.4
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Processing | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	7.3				7.3	15		11.1
Midstream services, Processing | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	35.7				2.2	56.8		2.2
Midstream services, Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	35.7				47.4	69.8		56.4
Midstream services, Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.8				1.1	1.7		1.7
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers	10				10.3	21.7		26.9
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, NGL services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, NGL services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	10				10.3	21.7		26.9
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers	23.4				15	46.4		27.9
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Crude services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	5.3				0.1	10.5		0.1
Midstream services, Crude services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	5.2				0	9.2		0.1
Midstream services, Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	12.9				14.9	26.7		27.7
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers	3.6				2.4	5.2		4.5
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Other services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	2.9				2	4.4		3.7
Midstream services, Other services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.3				0	0.5		0.3
Midstream services, Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.2				(0.1)	(0.1)		0
Midstream services, Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.2				0.5	0.4		0.5
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0		$ 175.2		175.2	0		341.4
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(0.9)				0	1.8		0
Midstream services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				4.3	0		8.6
Midstream services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				108.6	0		212.8
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	1.2				62.3	1.5		120
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	(0.3)				0	(3.3)		0
Midstream services, Gathering and transportation, related party
Segment Reporting
Revenue from contracts with customers					100.1			187.4
Midstream services, Gathering and transportation, related party | Corporate
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Gathering and transportation, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Gathering and transportation, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers					61.4			114
Midstream services, Gathering and transportation, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers					38.7			73.4
Midstream services, Gathering and transportation, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Processing, related party
Segment Reporting
Revenue from contracts with customers					69.9			143.6
Midstream services, Processing, related party | Corporate
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Processing, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Processing, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers					46.8			98.4
Midstream services, Processing, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers					23.1			45.2
Midstream services, Processing, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers					0			0
NGL services—related parties
Segment Reporting
Revenue from contracts with customers	0					0
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	0.3					3.3
NGL services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0					0
NGL services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0					0
NGL services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0					0
NGL services—related parties | Louisiana | Operating Segments
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				5	0		10
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(1.2)				0	(1.5)		0
Midstream services, Crude services, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				4.3	0		8.6
Midstream services, Crude services, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0				0	0		0
Midstream services, Crude services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	1.2				0.7	1.5		1.4
Midstream services, Crude services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	$ 0				0	$ 0		0
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers					0.2			0.4
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Other services, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers					0			0
Midstream services, Other services, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers					0.4			0.4
Midstream services, Other services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers					(0.2)			0
Midstream services, Other services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers					$ 0			$ 0
[1]	$5.8 million and $46.7 million for the three months ended June 30, 2019 and 2018 , respectively, and

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Segment Reporting [Abstract]
Segment profits	$ 292	$ 325.7	$ 325.7	$ 593.3	$ 596.7
General and administrative expenses	(32.2)	(30.4)		(83.6)	(57.9)
Loss on disposition of assets	(0.1)	(1.2)		(0.1)	(1.3)
Depreciation and amortization	(153.7)	(145.3)	$ (145.3)	(305.8)	(283.4)
Impairments	0	0		(186.5)	0
Loss on secured term loan receivable	(52.9)	0		(52.9)	0
Operating income (loss)	$ 53.1	$ 148.8		$ (35.6)	$ 254.1

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Segment Reporting
Assets	$ 10,393	$ 10,694.1
Operating Segments | Permian
Segment Reporting
Assets	2,386.1	2,096.8
Operating Segments | North Texas
Segment Reporting
Assets	1,346.7	1,308.2
Operating Segments | Oklahoma
Segment Reporting
Assets	3,881.7	3,209.5
Operating Segments | Louisiana
Segment Reporting
Assets	2,575.1	2,734.5
Corporate
Segment Reporting
Assets	$ 203.4	$ 1,345.1

Other Information (Details)

Other Information (Details) - USD ($)	Jun. 30, 2019	May 31, 2019	Dec. 31, 2018
Natural gas and NGLs inventory, prepaid expenses, and other:
Natural gas and NGLs inventory	$ 51,500,000		$ 41,300,000
Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1)	0		19,400,000
Secured term loan receivable, discount	800,000		1,100,000
Prepaid expenses and other	21,300,000		13,500,000
Natural gas and NGLs inventory, prepaid expenses, and other	72,800,000		74,200,000
Other current liabilities:
Accrued interest	41,100,000		37,500,000
Accrued wages and benefits, including taxes	18,600,000		37,200,000
Accrued ad valorem taxes	25,800,000		28,100,000
Capital expenditure accruals	44,900,000		50,600,000
Onerous performance obligations	0		9,000,000
Short-term lease liability	22,100,000		1,500,000
Suspense producer payments	15,400,000		34,600,000
Deferred revenue	48,600,000		6,600,000
Other	27,000,000		43,100,000
Other current liabilities	$ 243,500,000		$ 248,200,000
Second Lien Secured Term Loan
Natural gas and NGLs inventory, prepaid expenses, and other:
Maximum borrowing capacity		$ 58,000,000

Uncategorized Items - enlcq2201

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 300,000
Noncontrolling Interest [Member]
Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest	3,245,300,000
AOCI Including Portion Attributable to Noncontrolling Interest [Member]
Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest	$ (2,000,000)
Common Stock [Member]
Common Unit, Issued	us-gaap_CommonUnitIssued	181,300,000
Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 1,731,200,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	300,000
Redeemable Noncontrolling Interest [Member]
Redeemable Noncontrolling Interest, Equity, Carrying Amount	us-gaap_RedeemableNoncontrollingInterestEquityCarryingAmount	$ 9,300,000