EnLink Midstream Partners (ENLK) 10-K 26 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 19, 2020
Document And Entity Information [Abstract]
Entity Small Business	false
Entity Incorporation, State or Country Code	DE
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Amendment Flag	false
Entity Registrant Name	ENLINK MIDSTREAM PARTNERS, LP
Entity Central Index Key	0001179060
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		144,358,720
Entity Public Float	$ 0
Document Annual Report	true
Document Transition Report	false
Entity File Number	001-36340
Entity Tax Identification Number	16-1616605
Entity Address, Address Line One	1722 Routh St.,
Entity Address, Address Line Two	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
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Emerging Growth Company	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 77.4	$ 99.5
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively	36.2	126.3
Accrued revenue and other	460.1	705.9
Related party	18.1	2.1
Fair value of derivative assets	12.9	28.6
Natural gas and NGLs inventory, prepaid expenses, and other	56.9	72.8
Total current assets	661.6	1,035.2
Property and equipment, net of accumulated depreciation of $3,418.6 and $2,967.4, respectively	7,081.3	6,846.7
Intangible assets, net of accumulated amortization of $545.9 and $422.2, respectively	1,249.9	1,373.6
Goodwill	0	190.3
Investment in unconsolidated affiliates	43.1	80.1
Fair value of derivative assets	4.3	4.1
Other assets, net	94.4	41.3
Total assets	9,134.6	9,571.3
Current liabilities:
Accounts payable and drafts payable	70.6	105.5
Accounts payable to related party	1.1	4.3
Accrued gas, NGLs, condensate, and crude oil purchases	354.8	500.4
Fair value of derivative liabilities	14.4	21.8
Current maturities of long-term debt	0	399.8
Other current liabilities	201.7	246.7
Total current liabilities	642.6	1,278.5
Long-term debt, including $1,700.0 from affiliates	4,764.3	3,919.8
Asset retirement obligations	15.5	14.8
Other long-term liabilities	90.8	20
Deferred tax liability	44.5	42.4
Fair value of derivative liabilities	6.8	2.4
Redeemable non-controlling interest	5.2	9.3
Partners’ equity:
Common unitholders (144,358,720 and 353,117,434 units issued and outstanding, respectively)	1,681.2	2,460.8
General partner interest (1,594,974 equivalent units outstanding)	216.6	231.2
Accumulated other comprehensive loss	(14.5)	(2.1)
Non-controlling interest	391.4	309.8
Total partners’ equity	3,564.9	4,284.1
Commitments and contingencies (Note 13)
Total liabilities and partners’ equity	9,134.6	9,571.3
Series B Preferred Unitholders
Partners’ equity:
Preferred unitholders	895.1	889.3
Series C Preferred Unitholders
Partners’ equity:
Preferred unitholders	$ 395.1	$ 395.1

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Allowance for bad debt	$ 0.5	$ 0.3
Accumulated depreciation	3,418.6	2,967.4
Accumulated amortization	545.9	422.2
Long-term Debt, Excluding Current Maturities	$ 4,764.3	$ 3,919.8
Common units issued (in shares)	144,358,720	353,117,434
Common units outstanding (in shares)	144,358,720	353,117,434
General partner interest, equivalent units outstanding (in shares)	1,594,974	1,594,974
Series B Preferred Unitholders
Preferred units issued (in shares)	59,599,550	58,728,994
Preferred unit outstanding (in shares)	59,599,550	58,728,994
Series C Preferred Unitholders
Preferred unit outstanding (in shares)	400,000	400,000
Related party debt
Long-term Debt, Excluding Current Maturities	$ 1,700	$ 0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Revenue from contracts with customers		$ 6,038.5	$ 7,693.8
Gain (loss) on derivative activity		14.4	5.2	$ (4.2)
Total revenues		6,052.9	7,699	5,739.6
Operating costs and expenses:
Cost of sales	[1]	4,392.5	6,008	4,361.5
Operating expenses		467.1	453.4	418.7
General and administrative		139.2	130.2	123.5
(Gain) loss on disposition of assets		(1.9)	0.4	0
Depreciation and amortization		617	577.3	545.3
Impairments		198.2	365.8	17.1
Loss on secured term loan receivable		52.9	0	0
Gain on litigation settlement		0	0	(26)
Total operating costs and expenses		5,865	7,535.1	5,440.1
Operating income		187.9	163.9	299.5
Other income (expense):
Interest expense, net of interest income	[2]	(215.7)	(178.3)	(187.9)
Gain on extinguishment of debt		0	0	9
Income (loss) from unconsolidated affiliates		(16.8)	13.3	9.6
Other income		0.9	0.6	0.6
Total other expense		(231.6)	(164.4)	(168.7)
Income (loss) before non-controlling interest and income taxes		(43.7)	(0.5)	130.8
Income tax benefit (expense)		(2.5)	2.1	24
Net income (loss)		(46.2)	1.6	154.8
Net income attributable to non-controlling interest		8.1	2.1	1.1
Net income (loss) attributable to ENLK		(54.3)	(0.5)	153.7
Product sales
Revenues:
Revenue from contracts with customers		5,030.1	6,512.3	4,358.4
Product sales—related parties
Revenues:
Revenue from contracts with customers		0	41	144.9
Midstream services
Revenues:
Revenue from contracts with customers		1,008.4	763.3	552.3
Midstream services—related parties
Revenues:
Revenue from contracts with customers		$ 0	$ 377.2	$ 688.2
[1]	Includes related party cost of sales of $21.7 million , $114.1 million , and $211.0 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.
[2]	Includes related party interest expense of $66.0 million for the year ended December 31, 2019 .

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest expense, net of interest income	[1]	$ (215.7)	$ (178.3)	$ (187.9)
Related party cost of sales		21.7	$ 114.1	$ 211
Related party debt
Interest expense, net of interest income	[1]	$ (66)
[1]	Includes related party interest expense of $66.0 million for the year ended December 31, 2019 .

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (46.2)	$ 1.6	$ 154.8
Loss on designated cash flow hedge	(12.4)	0	(2.1)
Comprehensive income (loss)	(58.6)	1.6	152.7
Comprehensive income attributable to non-controlling interest	8.1	2.1	1.1
Comprehensive income (loss) attributable to ENLK	$ (66.7)	$ (0.5)	$ 151.6

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Devon	Non-Controlling Interest	Redeemable Non-Controlling Interest (Temporary Equity)	Accumulated Other Comprehensive Loss	General Partner Interest	Common UnitsLimited Partner	Common UnitsLimited PartnerDevon	Series B Preferred UnitholdersLimited Partner	Series C Preferred UnitholdersLimited Partner
Beginning balance at Dec. 31, 2016	$ 4,640.4		$ 181		$ 0	$ 203.6	$ 3,461.8		$ 794	$ 0
Beginning balance (in shares) at Dec. 31, 2016						1.6	342.9		53.2	0
Increase (Decrease) in Partners' Capital
Issuance of common units	106.9						$ 106.9
Issuance of common units (in shares)							6.2
Issuance of Series C Preferred Units	394					$ 0				$ 394
Issuance of Series C Preferred Units (in shares)										0.4
Contribution from Devon		$ 1.3						$ 1.3
Conversion of restricted units for common units, net of units withheld for taxes	(5.3)						$ (5.3)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)							0.6
Unit-based compensation	42.3					21.1	$ 21.2			$ 0
Distributions	(653.2)		(26.9)	$ (0.6)		(61.2)	(543.6)		$ (15.9)	(5.6)
Distributions (in shares)									3.9
Non-controlling interest contributions	126.4		126.4
Loss on designated cash flow hedge	(2.1)				(2.1)
Adjustment for acquisition of EOGP			(48.4)				48.4
Net income (loss)	154.8		1.1			43.1	17.9		$ 86	6.7
Ending balance at Dec. 31, 2017	4,805.5		233.2		(2.1)	$ 206.6	$ 3,108.6		$ 864.1	$ 395.1
Ending balance (in shares) at Dec. 31, 2017						1.6	349.7		57.1	0.4
Beginning balance at Dec. 31, 2016				5.2
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions	(653.2)		(26.9)	(0.6)		$ (61.2)	$ (543.6)		$ (15.9)	$ (5.6)
Net income (loss)	154.8		1.1			43.1	17.9		86	6.7
Ending balance at Dec. 31, 2017				4.6
Increase (Decrease) in Partners' Capital
Issuance of common units	46.1						$ 46.1
Issuance of common units (in shares)							2.6
Conversion of restricted units for common units, net of units withheld for taxes	(5.6)						$ (5.6)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)							0.8
Unit-based compensation	41.8					20.4	$ 21.4
Distributions	(757)		(54.5)			(61.9)	(551.6)		$ (65)	(24)
Distributions (in shares)									1.6
Non-controlling interest contributions	156.4		156.4
Loss on designated cash flow hedge	0
Fair value adjustment related to redeemable non-controlling interest	(4.1)			4.1			(4.1)
Adjustment for acquisition of EOGP			(26.8)				26.8
Net income (loss)	1		1.5	0.6		66.1	(180.8)		$ 90.2	24
Ending balance at Dec. 31, 2018	4,284.1		309.8		(2.1)	$ 231.2	$ 2,460.8		$ 889.3	$ 395.1
Ending balance (in shares) at Dec. 31, 2018						1.6	353.1		58.7	0.4
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions	(757)		(54.5)			$ (61.9)	$ (551.6)		$ (65)	$ (24)
Fair value adjustment related to redeemable non-controlling interest	(4.1)			4.1			(4.1)
Net income (loss)	1		1.5	0.6		66.1	$ (180.8)		90.2	24
Ending balance at Dec. 31, 2018				9.3
Increase (Decrease) in Partners' Capital
Issuance of common units (in shares)							55.8
Conversion of restricted units for common units, net of units withheld for taxes	(2.8)						$ (2.8)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)							0.5
Unit-based compensation	38.4					37	$ 1.4
Distributions	(797.8)		(23.8)	(0.3)		(15.6)	(667)		$ (67.4)	(24)
Distributions (in shares)									0.9
Non-controlling interest contributions	97.5		97.5
Loss on designated cash flow hedge	(12.4)				(12.4)
Fair value adjustment related to redeemable non-controlling interest	4			(4)			4
Net income (loss)	(46.4)		7.9	0.2		(36)	$ (115.5)		$ 73.2	24
Conversion of ENLK common units into ENLC units (in shares)							(265)
Ending balance at Dec. 31, 2019	3,564.9		391.4		$ (14.5)	$ 216.6	$ 1,681.2		$ 895.1	$ 395.1
Ending balance (in shares) at Dec. 31, 2019						1.6	144.4		59.6	0.4
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions	(797.8)		(23.8)	(0.3)		$ (15.6)	$ (667)		$ (67.4)	$ (24)
Fair value adjustment related to redeemable non-controlling interest	4			(4)			4
Net income (loss)	$ (46.4)		$ 7.9	0.2		$ (36)	$ (115.5)		$ 73.2	$ 24
Ending balance at Dec. 31, 2019				$ 5.2

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (46.2)	$ 1.6	$ 154.8
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	198.2	365.8	17.1
Depreciation and amortization	617	577.3	545.3
Loss on secured term loan receivable	52.9	0	0
Non-cash revenue from contract restructuring	0	(45.5)	0
Non-cash unit-based compensation	39.2	40.8	47.8
Deferred tax expense (benefit)	2.1	(3.9)	(26.6)
(Gain) loss on derivative activity recognized in net income (loss)	(14.4)	(5.2)	4.2
Cash settlements on derivatives	16.9	(7)	(11.2)
Gain on extinguishment of debt	0	0	(9)
Amortization of debt issue costs, net (premium) discount of notes and installment payable	4.9	4	29.1
Distribution of earnings from unconsolidated affiliates	16.5	15.8	13.3
(Income) loss from unconsolidated affiliates	16.8	(13.3)	(9.6)
Other operating activities	(4.1)	(2.2)	0.6
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	320.3	(114.6)	(189.5)
Natural gas and NGLs inventory, prepaid expenses, and other	12.7	(12.2)	(23.7)
Accounts payable, accrued product purchases, and other accrued liabilities	(248.3)	55.4	163.9
Net cash provided by operating activities	984.5	856.8	706.5
Cash flows from investing activities:
Additions to property and equipment	(754.9)	(843.1)	(790.8)
Proceeds from sale of unconsolidated affiliate investment	0	0	189.7
Proceeds from sale of property	14.3	1.9	2.3
Investment in unconsolidated affiliates	0	(0.1)	(12.6)
Distribution from unconsolidated affiliates in excess of earnings	3.7	6.9	0.2
Other investing activities	(4.6)	8.1	0.4
Net cash used in investing activities	(741.5)	(826.3)	(610.8)
Cash flows from financing activities:
Proceeds from borrowings	4,160	3,904	2,315.9
Payments on borrowings	(3,710)	(3,054)	(2,104.3)
Payment of installment payable for EOGP acquisition	0	(250)	(250)
Debt financing costs	(10)	(1.7)	(5.5)
Proceeds from issuance of common units	0	46.1	106.9
Distribution to common unitholders and to general partner	(682.6)	(613.5)	(604.8)
Distributions to non-controlling interests	(24.1)	(54.5)	(27.5)
Contributions by non-controlling interests, including contributions from ENLC of $66.2 million and $69.1 million for the years ended December 31, 2018 and 2017, respectively	97.5	156.4	126.4
Other financing activities	(4.5)	(5.6)	(6.1)
Net cash provided by (used in) financing activities	(265.1)	38.2	(76.5)
Net increase (decrease) in cash and cash equivalents	(22.1)	68.7	19.2
Cash and cash equivalents, beginning of period	99.5	30.8	11.6
Cash and cash equivalents, end of period	77.4	99.5	30.8
Series B Preferred Unitholders
Cash flows from financing activities:
Distributions to Preferred Unitholders	(67.4)	(65)	(15.9)
Series C Preferred Unitholders
Cash flows from financing activities:
Proceeds from issuance of Series C Preferred Units	0	0	394
Distributions to Preferred Unitholders	$ (24)	$ (24)	$ (5.6)

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Proceeds from affiliates	$ 97.5	$ 156.4
Affiliates
Proceeds from affiliates	$ 66.2	$ 69.1

Organization and Summary of Sig

Organization and Summary of Significant Agreements	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Agreements	(1) Organization and Summary of Significant Agreements (a) Organization of Business ENLK is a Delaware limited partnership formed in 2002. Our business activities are conducted through the Operating Partnership and the subsidiaries of the Operating Partnership. EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is a direct, wholly-owned subsidiary of ENLC. ENLC’s units are traded on the NYSE under the symbol “ENLC.” ENLC’s managing member is a wholly-owned subsidiary of GIP. EOGP Acquisition and Transfer of EOGP Interest On January 7, 2016, EOGP, an indirect subsidiary of ENLK, completed its acquisition of 100% of the issued and outstanding membership interests of TOMPC LLC and TOM-STACK, LLC. As a result of the acquisition, the Operating Partnership acquired an 83.9% limited partner interest in EOGP, and ENLC acquired the remaining 16.1% limited partner interest in EOGP. 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. This acquisition has been accounted for as an acquisition under common control under ASC 805, Business Combinations, resulting in the retrospective adjustment of our prior results. The “Adjustment for acquisition of EOGP (Note 1)” presented in the consolidated statements of changes in partners’ equity represents the adjustment due to the recast to offset distributions paid to ENLC and contributions received from ENLC for its related ownership in EOGP. Devon Transaction In 2014, we completed a series of transactions with Devon pursuant to which Devon contributed certain subsidiaries and assets to us in exchange for a majority interest in us (the “Devon Transaction”). GIP Transaction On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. As a result of the transaction: • GIP, through GIP III Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the managing member of ENLC , which, as of the closing date, amounted to 100% of the outstanding limited liability company interests in the managing member of ENLC and approximately 23.1% of the outstanding limited partner interests in ENLK; • GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of the closing date, amounted to approximately 63.8% of the outstanding limited liability company interests in ENLC; and • Through this transaction, GIP acquired control of (i) the managing member of ENLC, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of our general partner. Simplification of the Corporate Structure On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the outstanding common units of ENLK . 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 ENLC owning all of the remaining outstanding ENLK common units. • Our general partner’s incentive distribution rights in ENLK were eliminated. • Certain terms of the Series B Preferred Units were modified pursuant to an amended partnership agreement of ENLK. See “ Note 8—Partners' Capital ” 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. ENLC also agreed to issue an additional ENLC Class C Common Unit to the applicable holder of each Series B Preferred Unit for each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions. 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 our 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 was converted into 1.15 awards 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 and the 2014 Plan was modified such that the performance metric for any then outstanding performance 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, ENLC 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. (b) Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. Our midstream energy asset network includes approximately 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 290,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers. Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, barge, truck, or rail terminal.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with GAAP for complete financial statements. Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources, in connection with which certain reclassifications were made to the financial statements for prior periods to conform to current period presentation. The effect of these reclassifications had no impact on previously reported partners’ equity or net income (loss). See “ Note 14—Segment Information ” for additional information regarding the change in reportable operating segments. All significant intercompany balances and transactions have been eliminated in consolidation. (b) Management’s Use of Estimates The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. (c) Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. 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. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales— Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services— Midstream services represent all other revenue generated as a result of performing our midstream services outlined above. Adoption of ASC 606 Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaced previous revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also requires significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Evaluation of Our Contractual Performance Obligations In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include: • promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and • promises to sell a specified volume of commodities to our customers. The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For the year ended December 31, 2018 , the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $671.0 million , or 8.0% , compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows. Changes in Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories: • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations. For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606. Satisfaction of Performance Obligations and Recognition of Revenue While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). 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 year ended December 31, 2019 , we had contractual commitments of $154.0 million under our MVC contracts and recorded $19.7 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2020 $ 262.7 2021 111.0 2022 97.6 2023 92.7 2024 81.3 Thereafter 158.2 Total $ 803.5 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. Contributions in Aid of Construction The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for the year ended December 31, 2018. Disaggregation of Revenue and Presentation of Prior Periods Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. See “ Note 14—Segment Information ” for the revenue disaggregation information included in the segment information table for the years ended December 31, 2019 and 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the years ended December 31, 2019 and 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606. (d) 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. In November 2019, White Star sold its assets and we did not recover any amounts then 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 year ended December 31, 2019, which represents a full write-down of the second lien secured term loan. (e) Gas Imbalance Accounting Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. We had imbalance payables of $5.7 million and $12.4 million at December 31, 2019 and 2018 , respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $6.4 million and $10.4 million at December 31, 2019 and 2018 , respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued gas, NGLs, condensate, and crude oil purchases,” respectively, on the consolidated balance sheets. (f) Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. (g) Income Taxes Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. We record deferred tax assets and liabilities on a net basis on the consolidated balance sheets, with deferred tax assets included in “Other assets, net” and deferred tax liabilities included in “Deferred tax liability, net.” (h) Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory Our inventories of products consist of natural gas, NGLs, crude oil, and condensate. We report these assets at the lower of cost or market value which is determined by using the first-in, first-out method. (i) Property and Equipment Property and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest costs for material projects are capitalized to property and equipment during the period the assets are undergoing preparation for intended use. The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2019 2018 Transmission assets $ 1,376.5 $ 1,329.4 Gathering systems 4,856.5 4,410.5 Gas processing plants 3,862.2 3,590.5 Other property and equipment 188.0 171.7 Construction in process 216.7 312.0 Property and equipment 10,499.9 9,814.1 Accumulated depreciation (3,418.6 ) (2,967.4 ) Property and equipment, net of accumulated depreciation $ 7,081.3 $ 6,846.7 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years Depreciation expense of $490.7 million , $453.8 million , and $418.2 million was recorded for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the statement of operations. For the year ended December 31, 2019, we disposed of assets with a net book value of $12.4 million , and these dispositions primarily related to the sale of certain non-core assets. This decrease in book value was offset by $14.3 million of proceeds from the sale of property, resulting in a $1.9 million gain on disposition of assets in the consolidated statement of operations for the year ended December 31, 2019. For the year ended December 31, 2018, we disposed of assets with a net book value of $2.1 million . These dispositions primarily related to vehicle retirements and retirements due to compressor fire damage. This decrease in book value was offset by $1.7 million of proceeds from the sale of property, resulting in $0.4 million loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2018 . For the year ended December 31, 2017, we disposed of assets with a net book value of $8.4 million , and these dispositions primarily related to the retirement of compressors due to fire damage. This decrease in book value was offset by $6.1 million in insurance settlements and $2.3 million of proceeds from the sale of property, resulting in no gain or loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2017 . Impairment Review . In accordance with ASC 360, Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment annually in the fourth quarter, and whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding: • the future fee-based rate of new business or contract renewals; • the purchase and resale margins on natural gas, NGLs, crude oil, and condensate; • the volume of natural gas, NGLs, crude oil, and condensate available to the asset; • markets available to the asset; • operating expenses; and • future natural gas, NGLs, crude oil, and condensate prices. The amount of availability of natural gas, NGLs, crude oil, and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil, and condensate prices. Projections of natural gas, NGL, crude oil, and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: • changes in general economic conditions in regions in which our markets are located; • the availability and prices of natural gas, NGLs, crude oil, and condensate supply; • our ability to negotiate favorable sales agreements; • the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful; • our dependence on certain significant customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and • competition from other midstream companies, including major energy companies. For the year ended December 31, 2019, we recognized a $7.9 million impairment on property and equipment related to certain decommissioned and removed non-core assets. For the year ended December 31, 2018 , we determined that the undiscounted cash flows for two of our assets were not in excess of their carrying values. We estimated the fair values of these assets and determined that their fair values were not in excess of their carrying values, which resulted in impairments on property and equipment of $24.6 million related to certain non-core natural gas pipeline assets in the Louisiana segment and $109.2 million related to non-core crude pipeline assets in the Permian segment. For the year ended December 31, 2017 , we recognized a $17.1 million impairment on property and equipment , which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. (j) Comprehensive Income (Loss) Comprehensive income (loss) is composed of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”). For additional information about the effect of financial instruments on comprehensive income (loss), see “ Note 11—Derivatives .” (k) Equity Method of Accounting We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations. We recognized a $31.4 million loss for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV . For additional information, see “ Note 9—Investment in Unconsolidated Affiliates .” (l) Non-controlling Interests We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all the assets and liabilities of an investment on our consolidated balance sheets and record non-controlling interest for the portion of the investment that we do not own. We include all of an investment’s results of operations on our consolidated statements of operations and record income attributable to non-controlling interests for the portion of the investment that we do not own. Our non-controlling interests for the years ended December 31, 2019 , 2018 , and 2017 relate to NGP’s 49.9% ownership of the Delaware Basin JV, Marathon Petroleum Corporation’s 50.0% ownership interest in the Ascension JV, and other minor non-controlling interests. (m) Goodwill Goodwill is the cost of an acquisition less th

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	(3) Goodwill and Intangible Assets Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform a goodwill impairment test. We may elect to perform a goodwill impairment test without completing a qualitative assessment. We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year cash flow multiples, and estimated future cash flows, including volume and price forecasts, capital expenditures, and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The table below provides a summary of our change in carrying amount of goodwill by segment (in millions) for the years ended December 31, 2019 and 2018, by assigned reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amounts of goodwill. Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2019 Balance, beginning of period $ — $ — $ 190.3 $ — $ — $ 190.3 Impairment — — (190.3 ) — — (190.3 ) Balance, end of period $ — $ — $ — $ — $ — $ — Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2018 Balance, beginning of period $ 29.3 $ 202.7 $ 190.3 $ — $ — $ 422.3 Impairment (29.3 ) (202.7 ) — — — (232.0 ) Balance, end of period $ — $ — $ 190.3 $ — $ — $ 190.3 Goodwill Impairment Analysis for the Year Ended December 31, 2019 During the fourth quarter of 2019, we performed a quantitative analysis as of October 31, 2019 for our annual goodwill impairment test. Subsequent to October 31, 2019, we determined that due to a significant decline in ENLC’s common unit price and the expected reduction in ENLC’s cash distribution paid to common unitholders, which was announced in January 2020, a change in circumstances had occurred that warranted an additional quantitative impairment test. We recorded a goodwill impairment loss of $190.3 million on our Oklahoma reporting unit. This amount is included in impairments in the consolidated statement of operations for the year ended December 31, 2019. Goodwill Impairment Analysis for the Year Ended December 31, 2018 During our annual goodwill impairment test for 2018, which was performed as of October 31, 2018, we determined, based upon our qualitative assessment, that no impairments of goodwill were required as of that date. However, subsequent to October 31, 2018, we determined that due to a significant decline in our unit price, a change in circumstances had occurred that warranted a quantitative impairment test. Based on this triggering event, we performed a quantitative goodwill impairment analysis as of December 31, 2018. Based on this analysis, a goodwill impairment loss for our Permian and North Texas reporting units in the amounts of $29.3 million and $202.7 million , respectively, was recognized in the fourth quarter of 2018 and is included in impairments in the consolidated statement of operations for the year ended December 31, 2018. We concluded that the fair value of our Oklahoma and Corporate reporting units exceeded their carrying values, and the amounts of goodwill disclosed on the consolidated balance sheet associated with these reporting units were recoverable. Therefore, no goodwill impairment was identified or recorded for these reporting units as a result of our quantitative impairment test. Goodwill Impairment Analysis for the Year Ended December 31, 2017 During our annual impairment test for 2017, performed as of October 31, 2017, we determined that no impairments were required for the year ended December 31, 2017 . 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 for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2019 Customer relationships, beginning of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Amortization expense — (123.7 ) (123.7 ) Customer relationships, end of period $ 1,795.8 $ (545.9 ) $ 1,249.9 Year Ended December 31, 2018 Customer relationships, beginning of period $ 1,795.8 $ (298.7 ) $ 1,497.1 Amortization expense — (123.5 ) (123.5 ) Customer relationships, end of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Year Ended December 31, 2017 Customer relationships, beginning of period $ 1,795.8 $ (171.6 ) $ 1,624.2 Amortization expense — (127.1 ) (127.1 ) Customer relationships, end of period $ 1,795.8 $ (298.7 ) $ 1,497.1 For the years ended December 31, 2019 , 2018 , and 2017 , we reviewed our various assets groups for impairment during our annual impairment review process and determined that no impairment of our intangible assets occurred. We utilized Level 3 fair value measurements in our impairment analysis, which included cash flow assumptions consistent with those utilized in our goodwill impairment analysis. The weighted average amortization period for intangible assets is 15.0 years . Amortization expense was $123.7 million , $123.5 million , and $127.1 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 $ 123.7 2021 123.7 2022 123.7 2023 123.6 2024 123.4 Thereafter 631.8 Total $ 1,249.9

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions (a) Transactions with ENLC Simplification of the Corporate Structure . On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the outstanding common units of ENLK . See “ Note 1—Organization and Summary of Significant Agreements ” for more information on the Merger and related transactions. 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. See “ Note 1—Organization and Summary of Significant Agreements ” for more information on the Merger and related transactions. ENLC paid us $26.6 million and $48.4 million for its interest in EOGP’s capital expenditures for the years ended December 31, 2018 and 2017, respectively. ENLC paid its contribution for EOGP’s capital expenditures to ENLK monthly, net of EOGP’s adjusted EBITDA distributable to ENLC , which was defined as earnings before depreciation and amortization and provision for income taxes and included allocated expenses from us. ENLC paid us $2.5 million and $2.4 million as reimbursement during the years ended December 31, 2018 and 2017, respectively, to cover its portion of administrative and compensation costs for officers and employees that performed services for ENLC. Officers and employees that performed services for ENLC provided an estimate of the portion of their time devoted to such services. A portion of their annual compensation (including bonuses, payroll taxes, and other benefit costs) was allocated to ENLC for reimbursement based on these estimates. In addition, an administrative burden was added to such costs to reimburse us for additional support costs, including, but not limited to, consideration for rent, office support, and information service support. Subsequent to the closing of the Merger, ENLC no longer is allocated these administrative and compensation costs. Related Party Debt . Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes due 2029 to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. See “ Note 6—Long-Term Debt ” for more information on this arrangement. We had accounts receivable balances related to transactions with ENLC of $18.1 million and $1.4 million at December 31, 2019 and December 31, 2018 , respectively. (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. See “ Note 1—Organization and Summary of Significant Agreements ” for additional information regarding the GIP Transaction. 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 years ended December 31, 2018 and 2017 , related party revenues from Devon accounted for 5.4% and 14.4% of our revenues, respectively. Gathering and Processing Agreements with Devon On January 1, 2014, we entered into 10 -year gathering and processing agreements with Devon to provide gathering, treating, compression, dehydration, stabilization, processing, and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon (“Gas Services”), to our gathering and processing systems in the Barnett, Cana-Woodford, and Arkoma-Woodford Shales. These agreements provide us with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas, and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified minimum daily volumes of natural gas to our gathering systems in the Barnett, Cana-Woodford, and Arkoma-Woodford Shales during each calendar quarter. From January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 , we recognized $321.3 million and $615.5 million of revenue, respectively, under these agreements. Included in these amounts of revenue recognized is revenue from MVCs attributable to Devon of $50.8 million from January 1, 2018 to July 18, 2018 and $81.9 million for the year ended December 31, 2017 . Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, we will take delivery of as much Devon natural gas as is permitted in accordance with applicable law. The gathering and processing agreements are fee-based, and we are paid a specified fee per MMBtu for natural gas gathered on our gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause. EOGP Agreement with Devon In January 2016, in connection with the acquisition of EOGP, we acquired a gas gathering and processing agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EOGP provides gathering, treating, compression, dehydration, stabilization, processing, and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement had an MVC that remained in place during each calendar quarter for four years and has an overall term of approximately 15 years . Additionally, the agreement provides EOGP with dedication of all of the natural gas owned or controlled by DEPC and produced from or attributable to existing and future wells located on certain oil, natural gas, and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. This agreement accounted for approximately $77.6 million and $100.4 million of our combined revenues from January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 , respectively. Other Commercial Relationships with Devon As noted above, we continue to maintain a customer relationship with Devon pursuant to which we provide gathering, transportation, processing, and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. In addition, we have agreements with Devon pursuant to which we purchase and sell NGLs, gas, and crude oil and pay or receive, as applicable, a margin-based fee. These NGL, gas, and crude oil purchase and sale agreements have month-to-month terms. These historical agreements collectively comprised $66.6 million and $78.0 million of our combined revenue from January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 , respectively. VEX Transportation Agreement In connection with our acquisition of the VEX assets from Devon, we were party to a five -year transportation services agreement with Devon pursuant to which we provided transportation services to Devon on the VEX pipeline. This agreement included a five -year MVC with Devon. The MVC was executed in June 2014 and expired June 2019. This agreement accounted for approximately $3.5 million and $17.8 million of service revenues from January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 , respectively. Acacia Transportation Agreement We entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which we provide transportation services to Devon on our Acacia pipeline in North Texas. This agreement accounted for approximately $4.9 million and $13.8 million of our combined revenues from January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 , respectively. (c) Transactions with Cedar Cove JV For the years ended December 31, 2018 and December 31, 2017, we recorded service revenue of $0.5 million and $5.4 million , respectively, that is recorded as “Midstream services—related parties” on the consolidated statements of operations. Additionally, for the years ended December 31, 2019 , 2018 , and 2017 , we recorded cost of sales of $21.7 million , $44.1 million , $30.6 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 balance related to transactions with the Cedar Cove JV at December 31, 2019 and $0.7 million at December 31, 2018 . We had an accounts payable balance related to transactions with the Cedar Cove JV of $1.1 million and $4.3 million at December 31, 2019 and 2018 , respectively. (d) Tax Sharing Agreement We, ENLC , and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities, and benefits relating to any tax for which a combined tax return is due. From January 1, 2018 to July 18, 2018 and for the year ended December 31, 2017 we incurred approximately $0.4 million and $1.2 million , respectively, in taxes that are subject to the tax sharing agreement. Effective July 18, 2018, ENLK, ENLC, and Devon signed a supplemental agreement reaffirming terms of the tax sharing agreement for tax periods ending July 18, 2018 and prior. 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	12 Months Ended
	Dec. 31, 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 $60.0 million of our lease liability and $39.8 million of our right-of-use asset as of December 31, 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 $27.1 million of our lease liability and $27.1 million of our right-of-use asset as of December 31, 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 $0.6 million of our lease liability and $0.6 million of our right-of-use asset as of December 31, 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 $15.3 million of our lease liability and $12.9 million of our right-of-use asset as of December 31, 2019 . Lease balances are recorded on the consolidated balance sheets as follows (in millions): December 31, 2019 Operating leases: Other assets, net $ 80.4 Other current liabilities $ 21.1 Other long-term liabilities $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 10.6 years Weighted-average discount rate—Operating leases 5.1 % 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): Year Ended December 31, 2019 Finance lease expense: Amortization of right-of-use asset $ 5.2 Interest on lease liability 0.1 Operating lease expense: Long-term operating lease expense 28.7 Short-term lease expense 32.0 Variable lease expense 7.7 Total lease expense $ 68.4 Other information about our leases is presented below (in millions): Year Ended December 31, 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 1.2 Cash payments for operating leases included in cash flows from operating activities $ 29.8 Right-of-use assets obtained in exchange for operating lease liabilities $ 104.1 The following table summarizes the maturity of our lease liability as of December 31, 2019 (in millions): Total 2020 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 141.2 $ 25.0 $ 18.7 $ 11.7 $ 9.7 $ 9.1 $ 67.0 Reduction due to present value (38.2 ) (4.7 ) (3.9 ) (3.4 ) (3.1 ) (2.7 ) (20.4 ) Operating lease liability $ 103.0 $ 20.3 $ 14.8 $ 8.3 $ 6.6 $ 6.4 $ 46.6
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 $60.0 million of our lease liability and $39.8 million of our right-of-use asset as of December 31, 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 $27.1 million of our lease liability and $27.1 million of our right-of-use asset as of December 31, 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 $0.6 million of our lease liability and $0.6 million of our right-of-use asset as of December 31, 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 $15.3 million of our lease liability and $12.9 million of our right-of-use asset as of December 31, 2019 . Lease balances are recorded on the consolidated balance sheets as follows (in millions): December 31, 2019 Operating leases: Other assets, net $ 80.4 Other current liabilities $ 21.1 Other long-term liabilities $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 10.6 years Weighted-average discount rate—Operating leases 5.1 % 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): Year Ended December 31, 2019 Finance lease expense: Amortization of right-of-use asset $ 5.2 Interest on lease liability 0.1 Operating lease expense: Long-term operating lease expense 28.7 Short-term lease expense 32.0 Variable lease expense 7.7 Total lease expense $ 68.4 Other information about our leases is presented below (in millions): Year Ended December 31, 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 1.2 Cash payments for operating leases included in cash flows from operating activities $ 29.8 Right-of-use assets obtained in exchange for operating lease liabilities $ 104.1 The following table summarizes the maturity of our lease liability as of December 31, 2019 (in millions): Total 2020 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 141.2 $ 25.0 $ 18.7 $ 11.7 $ 9.7 $ 9.1 $ 67.0 Reduction due to present value (38.2 ) (4.7 ) (3.9 ) (3.4 ) (3.1 ) (2.7 ) (20.4 ) Operating lease liability $ 103.0 $ 20.3 $ 14.8 $ 8.3 $ 6.6 $ 6.4 $ 46.6

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of December 31, 2019 and 2018 , long-term debt consisted of the following (in millions): December 31, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Related party debt $ 1,700.0 $ — $ 1,700.0 $ — $ — $ — Term Loan due 2021 (1) — — — 850.0 — 850.0 2.70% Senior unsecured notes due 2019 (2) — — — 400.0 — 400.0 4.40% Senior unsecured notes due 2024 550.0 1.5 551.5 550.0 1.8 551.8 4.15% Senior unsecured notes due 2025 750.0 (0.7 ) 749.3 750.0 (0.9 ) 749.1 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.5 ) 499.5 5.60% Senior unsecured notes due 2044 350.0 (0.2 ) 349.8 350.0 (0.2 ) 349.8 5.05% Senior unsecured notes due 2045 450.0 (5.9 ) 444.1 450.0 (6.2 ) 443.8 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 $ 4,800.0 $ (5.9 ) 4,794.1 $ 4,350.0 $ (6.1 ) 4,343.9 Debt issuance cost (3) (29.8 ) (24.3 ) Less: Current maturities of long-term debt (2) — (399.8 ) Long-term debt, net of unamortized issuance cost $ 4,764.3 $ 3,919.8 ____________________________ (1) In December 2018, ENLK entered into an $850.0 million , three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2018 . In connection with the closing of the Merger, the Term Loan was assumed by ENLC, and we became a guarantor of the Term Loan. (2) The 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. (3) Net of accumulated amortization of $10.9 million and $15.3 million at December 31, 2019 and 2018 , respectively. Maturities Maturities for the long-term debt as of December 31, 2019 are as follows (in millions): 2020 $ — 2021 850.0 2022 — 2023 — 2024 900.0 Thereafter 3,050.0 Subtotal 4,800.0 Less: net discount (5.9 ) Less: debt issuance cost (29.8 ) Long-term debt, net of unamortized issuance cost $ 4,764.3 Related Party Debt Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes due 2029 to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. Interest charged to ENLK for borrowings made through the related party arrangement will be substantially the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes due 2029. As of December 31, 2019 , $1,700.0 million of related party debt is included in “Long-term debt” in the consolidated balance sheet related to these borrowings. The indebtedness under ENLC's 5.375% senior unsecured notes due June 1, 2029, the Consolidated Credit Facility, and the Term Loan was incurred by ENLC but is guaranteed by ENLK. Therefore, the covenants in the agreements governing such indebtedness described below affect balances owed by ENLK on the related party debt. 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 ( $350.0 million as of December 31, 2019 ), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ( $4.8 million as of December 31, 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 (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00% ) or the Base Rate (the highest of the Federal Funds Rate plus 0.50% , the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00% ). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately. At December 31, 2019 , ENLC was in compliance with and expects to be in compliance with the covenants of the Consolidated Credit Facility for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $350.0 million outstanding on the Consolidated Credit Facility. 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 , and borrowed $850.0 million under the Term Loan. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan and the outstanding balance becomes due, ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance of the Term Loan was $850.0 million as of December 31, 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 (LIBOR) plus an applicable margin (ranging from 1.0% to 1.75% ) or the Base Rate (the highest of the Federal Funds Rate plus 0.5% , the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75% ). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately. At December 31, 2019 , ENLC was in compliance with and expects to be in compliance with the covenants of the Term Loan for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $850.0 million outstanding on the Term Loan. Issuances and Redemptions of Senior Unsecured Notes On March 7, 2014, we recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022. The interest payments on the 2022 Notes were due semi-annually in arrears in June and December. The 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million , including a premium of $29.5 million . On July 20, 2014, we redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million , including accrued interest. On September 20, 2014, we redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million , including accrued interest. On June 1, 2017, we redeemed the remaining $162.5 million in aggregate principal amount of the 2022 Notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million , which resulted in a gain on extinguishment of debt of $9.0 million for the year ended December 31, 2017. On March 19, 2014, we issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of our 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of our 4.400% senior notes due 2024 (the “2024 Notes”), and $350.0 million aggregate principal amount of our 5.600% senior notes due 2044 (the “2044 Notes”), at prices to the public of 99.850% , 99.830% , and 99.925% , respectively, of their face value. The 2019 Notes matured on April 1, 2019; the 2024 Notes mature on April 1, 2024; and the 2044 Notes mature on April 1, 2044. The interest payments on the 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October. On November 12, 2014, we issued an additional $100.0 million aggregate principal amount of the 2024 Notes and $300.0 million aggregate principal amount of our 5.050% senior notes due 2045 (the “2045 Notes”), at prices to the public of 104.007% and 99.452% , respectively, of their face value. The new 2024 Notes were offered as an additional issue of our outstanding 2024 Notes issued on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October. On May 12, 2015, we issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of our 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of 2045 Notes at prices to the public of 99.827% and 96.381% , respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of our outstanding 2045 Notes issued on November 12, 2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date. On July 14, 2016, we issued $500.0 million in aggregate principal amount of our 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year. On May 11, 2017, we issued $500.0 million in aggregate principal amount of our 5.450% senior unsecured notes due June 1, 2047 (the “2047 Notes”) at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. We received net proceeds of approximately $495.2 million for the issuance of the 2047 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 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. 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. Senior Unsecured Notes Redemption Provisions Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see "Early Redemption Date" in table below) at a redemption price equal to the greater of: (i) 100% of the principal amount of the notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the respective notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360 -day year consisting of twelve 30 -day months) at the applicable Treasury Rate plus a specified basis point premium (see "Basis Point Premium" in the table below); plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after the Early Redemption Date, the senior unsecured notes may be fully or partially redeemed at a redemption price equal to 100% of the principal amount of the applicable notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. See applicable redemption provision terms below: Issuance Maturity Date of Notes Early Redemption Date Basis Point Premium 2024 Notes April 1, 2024 Prior to January 1, 2024 25 Basis Points 2025 Notes June 1, 2025 Prior to March 1, 2025 30 Basis Points 2026 Notes July 15, 2026 Prior to April 15, 2026 50 Basis Points 2029 Notes June 1, 2029 Prior to March 1, 2029 50 Basis Points 2044 Notes April 1, 2044 Prior to October 1, 2043 30 Basis Points 2045 Notes April 1, 2045 Prior to October 1, 2044 30 Basis Points 2047 Notes June 1, 2047 Prior to June 1, 2047 40 Basis Points Senior Unsecured Notes Indentures The indentures governing the senior unsecured notes contain covenants that, among other things, limit ENLC’s and ENLK’s ability to create or incur certain liens or consolidate, merge, or transfer all or substantially all of ENLC’s and ENLK’s assets. Each of the following is an event of default under the indentures: • failure to pay any principal or interest when due; • failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures; and • bankruptcy or other insolvency events involving ENLC and ENLK. If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies. At December 31, 2019 , ENLC and ENLK were in compliance and expect to be in compliance with the covenants in the senior unsecured notes for at least the next twelve months.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	(7) Income Taxes The components of our income tax benefit (expense) are as follows (in millions): Year Ended December 31, 2019 2018 2017 Current income tax expense $ (0.4 ) $ (1.8 ) $ (2.6 ) Deferred tax benefit (expense) (2.1 ) 3.9 26.6 Total income tax benefit (expense) $ (2.5 ) $ 2.1 $ 24.0 Net income for financial statement purposes may differ significantly from taxable income (loss) of unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes is not available to us. The Tax Cuts and Jobs Act of 2017 resulted in a change in the federal statutory corporate tax rate from 35% to 21% , effective January 1, 2018. Accordingly, we recognized a tax benefit of $24.9 million during the fourth quarter of 2017 due to the remeasurement of our deferred tax liabilities to reflect the reduction in the federal statutory corporate tax rate. Deferred tax liabilities of $44.5 million and $42.4 million existed at December 31, 2019 and 2018 , respectively. Deferred tax liabilities as of December 31, 2019 and 2018 included $39.1 million and $38.7 million , respectively, related to our wholly-owned corporate entity that was formed to acquire the common stock of Clearfield Energy, Inc. This deferred tax liability represents the future tax payable on the difference between the fair value and the carryover tax basis of the assets acquired and is expected to become payable no later than 2027. For the years ended December 31, 2019 and 2018 , there was no recorded unrecognized tax benefit. Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2019 , tax years 2015 through 2019 remain subject to examination by various taxing authorities.

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2019
Partners' Capital Notes [Abstract]
Partners' Capital	(8) Partners' Capital (a) Issuance of Common Units In November 2014, we entered into the 2014 EDA to sell up to $350.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program. In August 2017, we ceased trading under the 2014 EDA and entered into the 2017 EDA. For the year ended December 31, 2017 , we sold an aggregate of 6.2 million common units under the 2014 EDA and the 2017 EDA, generating proceeds of $106.9 million (net of $1.1 million of commissions and $0.2 million of registration fees). We used the net proceeds for general partnership purposes. For the year ended December 31, 2018, we sold an aggregate of 2.6 million common units under the 2017 EDA, generating proceeds of $46.1 million (net of $0.5 million of commissions paid to the ENLK Sales Agents). We used the net proceeds for general partnership purposes. In connection with the announcement of the Merger, we suspended solicitation and offers under the 2017 EDA. Following the consummation of the Merger, the 2017 EDA was terminated. (b) Series B Preferred Units In January 2016, we issued an aggregate of 50,000,000 Series B Preferred Units representing our limited partner interests to Enfield in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”). Affiliates of Goldman Sachs and affiliates of TPG own interests in the general partner of Enfield. Prior to the close of the Merger, the Series B Preferred Units were convertible into our common units on a one -for-one basis, subject to certain adjustments. Subsequent to the Merger, Series B Preferred Units are exchangeable for ENLC common units in an amount equal to the number of outstanding Series B Preferred Units outstanding multiplied by the exchange ratio of 1.15 , subject to certain adjustments (the “Series B Exchange Ratio”). The exchange is subject to ENLK’s option to pay cash instead of issuing additional ENLC common units, and can occur in whole or in part at Enfield’s option at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units (the “ENLC VWAP”) exchange for the 30 trading days ending two trading days prior to the exchange is greater than 150% of the Issue Price divided by the conversion ratio of 1.15 . For each of the calendar quarters between March 31, 2016 through June 30, 2017, Enfield received a quarterly distribution equal to an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Series B Preferred Units. Beginning with the quarter ended September 30, 2017, 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 our common units over the Cash Distribution Component, divided by (ii) 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 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). Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2019 , 2018 , and 2017 is provided below: Declaration period Distribution Cash distribution Date paid/payable 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019 Second Quarter of 2019 148,257 $ 17.1 August 13, 2019 Third Quarter of 2019 148,627 $ 17.1 November 13, 2019 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 Third Quarter of 2018 422,720 $ 16.4 November 13, 2018 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 2017 First Quarter of 2017 1,154,147 $ — May 12, 2017 Second Quarter of 2017 1,178,672 $ — August 11, 2017 Third Quarter of 2017 410,681 $ 15.9 November 13, 2017 Fourth Quarter of 2017 413,658 $ 16.1 February 13, 2018 (d) Series C Preferred Units In September 2017, we issued 400,000 Series C Preferred Units representing our limited partner interests at a price to the public of $1,000 per unit. We used the net proceeds of $394.0 million for capital expenditures, general partnership purposes, and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in us and, unlike our indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to our common units and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event. At any time on or after December 15, 2022, we may redeem, at our option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. We may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by us following certain rating agency events, we may redeem, at our option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared. 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 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by our 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% . Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period. Following the Merger, the Series C Preferred Units remain issued and outstanding with the terms set forth above. (e) Common Unit Distributions Prior to the Merger, unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing our senior unsecured notes, we were required to make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions were made to the general partner in accordance with its then current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions were achieved. The general partner was not entitled to its incentive distributions with respect to the Class C Common Units issued in kind. In addition, the general partner was not entitled to its incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units convert into common units or (ii) the Series C Preferred Units. Prior to the Merger, our general partner owned the general partner interest in us and all of our incentive distribution rights . Our general partner was entitled to receive incentive distributions if the amount we distributed with respect to any quarter exceeded levels specified in its partnership agreement. Under the quarterly incentive distribution provisions, our general partner was entitled to 13.0% of amounts we distributed in excess of $0.25 per unit, 23.0% of the amounts we distributed in excess of $0.3125 per unit, and 48.0% of amounts we distributed in excess of $0.375 per unit. At the closing of the Merger, our general partner ’s incentive distribution rights in ENLK were eliminated. See “ Note 1—Organization and Summary of Significant Agreements ” for more information regarding the Merger and related transactions. 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 2018 First Quarter of 2018 $ 0.390 May 14, 2018 Second Quarter of 2018 $ 0.390 August 13, 2018 Third Quarter of 2018 $ 0.390 November 13, 2018 Fourth Quarter of 2018 $ 0.390 February 13, 2019 2017 First Quarter of 2017 $ 0.390 May 12, 2017 Second Quarter of 2017 $ 0.390 August 11, 2017 Third Quarter of 2017 $ 0.390 November 13, 2017 Fourth Quarter of 2017 $ 0.390 February 13, 2018 Following the Merger, we distributed $527.6 million to ENLC related to its ownership of our common units for the year ended December 31, 2019 . (f) Allocation of ENLK Income Prior to the closing of the Merger and for the years ended December 31, 2018 and 2017, net income was allocated to our general partner in an amount equal to its incentive distribution rights as described in section “(e) Common Unit Distributions” above. Our 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, our general partner ’s incentive distribution rights were eliminated. For the years ended December 31, 2018 and 2017, our 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 our general partner. For the years ended December 31, 2019 , 2018 , and 2017 , the net income allocated to the general partner is as follows (in millions): Year Ended December 31, 2019 2018 2017 Income allocation for incentive distributions $ — $ 59.5 $ 58.9 Unit-based compensation attributable to ENLC’s restricted and performance units (37.0 ) (20.3 ) (21.0 ) General partner share of net income (loss) (1.4 ) (0.6 ) 0.4 General partner interest in EOGP acquisition 2.4 27.5 4.8 General partner interest in net income (loss) $ (36.0 ) $ 66.1 $ 43.1

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates As of December 31, 2019, our unconsolidated investments consisted of a 38.75% ownership interest in GCF and a 30.0% 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): Year Ended December 31, 2019 2018 2017 GCF Distributions $ 19.2 $ 22.3 $ 12.7 Equity in income $ 16.5 $ 15.8 $ 12.6 HEP Equity in loss (1) $ — $ — $ (3.4 ) Cedar Cove JV Contributions $ — $ 0.1 $ 12.6 Distributions $ 1.0 $ 0.4 $ 0.8 Equity in income (loss) (2) $ (33.3 ) $ (2.5 ) $ 0.4 Total Contributions $ — $ 0.1 $ 12.6 Distributions $ 20.2 $ 22.7 $ 13.5 Equity in income (loss) (1)(2) $ (16.8 ) $ 13.3 $ 9.6 ___________________________ (1) Includes a loss of $3.4 million for the year ended December 31, 2017 related to the sale of our HEP interests . In March 2017, we sold an approximate 31.0% ownership interest in HEP for aggregate net proceeds of $189.7 million . (2) Includes a loss of $31.4 million for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV . The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2019 and 2018 (in millions): December 31, 2019 December 31, 2018 GCF $ 39.2 $ 41.9 Cedar Cove JV 3.9 38.2 Total investment in unconsolidated affiliates $ 43.1 $ 80.1

Employee Incentive Plans

Employee Incentive Plans	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Employee Incentive Plans	(10) 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, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plans awarded to ENLC’s directors, officers, and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Year Ended December 31, 2019 2018 2017 Cost of unit-based compensation charged to general and administrative expense $ 32.5 $ 30.0 $ 37.1 Cost of unit-based compensation charged to operating expense 6.7 10.8 10.7 Total unit-based compensation expense $ 39.2 $ 40.8 $ 47.8 All unit-based awards issued and outstanding immediately prior to the effective time of the Merger under the GP Plan have 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, with certain adjustments to the performance-based vesting of terms of applicable awards related to the performance of ENLC. (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 year ended December 31, 2019 is provided below: Year Ended December 31, 2019 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 years ended December 31, 2019 , 2018 , and 2017 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2019 2018 2017 Aggregate intrinsic value of units vested $ 8.0 $ 13.1 $ 16.6 Fair value of units vested $ 7.2 $ 16.4 $ 22.6 (c) EnLink Midstream Partners, LP Performance Units Prior to the Merger, our 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 and ENLC 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 . EnLink Midstream Partners, LP Performance Units: March 2018 March 2017 Grant-date fair value $ 19.24 $ 25.73 Beginning TSR price $ 15.44 $ 17.55 Risk-free interest rate 2.38 % 1.62 % Volatility factor 43.85 % 43.94 % Distribution yield 10.5 % 8.7 % The following table presents a summary of the performance units: Year Ended December 31, 2019 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 years ended December 31, 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 as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. No performance units vested for the year ended December 31, 2017. Year Ended December 31, EnLink Midstream Partners, LP Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 2.1 $ 5.0 Fair value of units vested $ 1.7 $ 7.7 (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 year ended December 31, 2019 is provided below: Year Ended December 31, 2019 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) 2,027,653 11.09 Vested (1)(2) (1,886,905 ) 12.06 Forfeited (606,276 ) 13.85 Converted from ENLK (3) 2,103,266 14.01 Non-vested, end of period 4,063,605 $ 13.85 Aggregate intrinsic value, end of period (in millions) $ 24.9 ____________________________ (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 626,133 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 years ended December 31, 2019 , 2018 , and 2017 is provided below (in millions): Year Ended December 31, EnLink Midstream, LLC Restricted Incentive Units: 2019 2018 2017 Aggregate intrinsic value of units vested $ 17.3 $ 12.8 $ 15.3 Fair value of units vested $ 22.8 $ 16.5 $ 22.2 As of December 31, 2019 , there were $23.1 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted average period of 1.6 years . For 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 Performance Units ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. 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. 2019 Performance Unit Awards For 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 “Manager 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 “Manager Committee”) of the Manager 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 Vesting percentage 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 Manager 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 Manager 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 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 (or for outstanding performance units granted prior to the Merger, ENLC and ENLK) 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: October 2019 June 2019 March 2019 March 2018 March 2017 Grant-date fair value $ 7.29 $ 9.92 $ 13.10 $ 21.63 $ 28.77 Beginning TSR price $ 7.42 $ 9.84 $ 10.92 $ 16.55 $ 18.29 Risk-free interest rate 1.44 % 1.72 % 2.42 % 2.38 % 1.62 % Volatility factor 35.00 % 33.50 % 33.86 % 51.36 % 52.07 % Distribution yield 10.1 % 11.5 % 9.7 % 6.7 % 5.4 % The following table presents a summary of the performance units: Year Ended December 31, 2019 EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 418,149 $ 19.15 Granted 1,202,105 11.73 Vested (1) (374,745 ) 21.08 Forfeited (261,451 ) 15.68 Converted from ENLK (2) 333,798 25.84 Non-vested, end of period 1,317,856 $ 14.22 Aggregate intrinsic value, end of period (in millions) $ 8.1 ____________________________ (1) Vested units included 146,218 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 years ended December 31, 2019 and 2018 is provided below (in millions). No performance units vested for the year ended December 31, 2017. Year Ended December 31, EnLink Midstream, LLC Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 3.4 $ 4.7 Fair value of units vested $ 7.9 $ 7.7 As of December 31, 2019 , there were $10.2 million of unrecognized compensation costs that related to non-vested performance units. These costs are expected to be recognized over a weighted-average period of 1.8 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 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. (f) Benefit Plan ENLK maintains a tax-qualified 401(k) plan whereby it matches 100% of every dollar contributed up to 6% of an employee’s eligible compensation plus a 2% non-discretionary contribution (not to exceed the maximum amount permitted by law). Contributions of $9.4 million , $8.3 million , and $7.6 million were made to the plan for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) 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 with ENLC, which mirrored the terms of ENLC’s interest rate swap with a third party, 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 our 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 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. In addition, the settlement loss was included as an operating cash outflow on the consolidated statement of cash flows for the year ended December 31, 2017. For the year ended December 31, 2019 , we recorded $12.4 million into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps. For the year ended December 31, 2019 , we realized a loss of $0.4 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 years ended December 31, 2018 and 2017 , we amortized an immaterial amount of the settlement loss into interest expense, net of interest income from accumulated other comprehensive loss . We expect to recognize an additional $5.7 million of interest expense out of accumulated other comprehensive loss over the next twelve months. The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): December 31, 2019 Fair value of derivative liabilities—current $ (5.6 ) Fair value of derivative liabilities—long-term (6.8 ) Net fair value of derivatives $ (12.4 ) 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 derivative 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 on 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): Year Ended December 31, 2019 2018 2017 Change in fair value of derivatives $ (0.1 ) $ 10.1 $ 4.7 Realized gain (loss) on derivatives 14.5 (4.9 ) (8.9 ) Gain (loss) on derivative activity $ 14.4 $ 5.2 $ (4.2 ) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): December 31, 2019 December 31, 2018 Fair value of derivative assets—current $ 12.9 $ 28.6 Fair value of derivative assets—long-term 4.3 4.1 Fair value of derivative liabilities—current (8.8 ) (21.8 ) Fair value of derivative liabilities—long-term — (2.4 ) Net fair value of derivatives $ 8.4 $ 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 December 31, 2019 (in millions). The remaining term of the contracts extend no later than December 2022 . December 31, 2019 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (64.0 ) $ 1.7 NGL (long contracts) Swaps Gallons 11.7 (0.5 ) Natural gas (short contracts) Swaps MMBtu (4.7 ) 1.0 Natural gas (long contracts) Swaps MMBtu 3.7 (0.4 ) Crude and condensate (short contracts) Swaps MMbbls (12.8 ) (1.0 ) Crude and condensate (long contracts) Swaps MMbbls 2.0 7.6 Total fair value of derivatives $ 8.4 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 $17.2 million as of December 31, 2019 would be reduced to $8.4 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	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	(12) 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, which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices 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. Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2019 December 31, 2018 Interest rate swaps (1) $ (12.4 ) $ — Commodity swaps (2) $ 8.4 $ 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): December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 4,764.3 $ 4,444.2 $ 4,319.6 $ 3,953.6 Obligations under financing lease $ — $ — $ 2.5 $ 2.2 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 the long-term debt is reduced by debt issuance costs of $29.8 million and $24.3 million at December 31, 2019 and 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 and was not 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 December 31, 2019 , ENLC had total borrowings under senior unsecured notes of $500.0 million maturing in 2029 with a fixed interest rate of 5.375% . As of December 31, 2019 , we had total borrowings under senior unsecured notes of $3.1 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 December 31, 2019 and 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(13) Commitments and Contingencies (a) Change of Control and Severance Agreements Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with our general partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about our general partner or interfering with a client or customer of our general partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment. (b) Environmental Issues The operation of pipelines, plants, and other facilities for the gathering, processing, transmitting, stabilizing, fractionating, storing, or disposing of natural gas, NGLs, crude oil, condensate, brine, and other products is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner, partner, or operator of these facilities, we must comply with United States laws and regulations at the federal, state, and local levels that relate to air and water quality, hazardous and solid waste management and disposal, oil spill prevention, climate change, endangered species, and other environmental matters. The cost of planning, designing, constructing, and operating pipelines, plants, and other facilities must account for compliance with environmental laws and regulations and safety standards. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition, or cash flows. However, we cannot provide assurance that future events, such as changes in existing laws, regulations, or enforcement policies, the promulgation of new laws or regulations, or the discovery or development of new factual circumstances will not cause us to incur material costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation. (c) Litigation Contingencies We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations, or cash flows. At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time we or our subsidiaries are party to lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated financial condition, results of operations, or cash flows. We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern in the area, and its insurers, as well as other parties we alleged to have contributed to the formation of the sinkhole seeking recovery for these losses. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers, and we subsequently reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million . We secured additional settlement payments during 2017, which resulted in the recognition of “Gain on litigation settlement” of $26.0 million on the consolidated statement of operations for the year ended December 31, 2017.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 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. Prior to January 1, 2019, 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 years ended December 31, 2018 and 2017 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. Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the years ended December 31, 2019 and 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606. 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 Year Ended December 31, 2019 Natural gas sales $ 94.3 $ 129.3 $ 236.4 $ 416.6 $ — $ 876.6 NGL sales 0.9 30.9 19.6 1,725.6 — 1,777.0 Crude oil and condensate sales 1,975.0 — 109.6 291.9 — 2,376.5 Product sales 2,070.2 160.2 365.6 2,434.1 — 5,030.1 Natural gas sales—related parties 0.4 — — — (0.4 ) — NGL sales—related parties 347.7 94.8 421.1 25.7 (889.3 ) — Crude oil and condensate sales—related parties 13.5 5.5 — 1.7 (20.7 ) — Product sales—related parties 361.6 100.3 421.1 27.4 (910.4 ) — Gathering and transportation 48.8 196.4 234.5 58.3 — 538.0 Processing 30.5 143.0 138.2 3.2 — 314.9 NGL services — 0.1 — 50.6 — 50.7 Crude services 19.2 — 19.8 51.9 — 90.9 Other services 12.0 1.1 0.1 0.7 — 13.9 Midstream services 110.5 340.6 392.6 164.7 — 1,008.4 NGL services—related parties — — — (3.4 ) 3.4 — Crude services—related parties — — 1.8 — (1.8 ) — Midstream services—related parties — — 1.8 (3.4 ) 1.6 — Revenue from contracts with customers 2,542.3 601.1 1,181.1 2,622.8 (908.8 ) 6,038.5 Cost of sales (2,283.9 ) (208.8 ) (627.0 ) (2,181.6 ) 908.8 (4,392.5 ) Operating expenses (112.9 ) (102.9 ) (104.0 ) (147.3 ) — (467.1 ) Gain on derivative activity — — — — 14.4 14.4 Segment profit $ 145.5 $ 289.4 $ 450.1 $ 293.9 $ 14.4 $ 1,193.3 Depreciation and amortization $ (119.8 ) $ (139.8 ) $ (194.9 ) $ (154.1 ) $ (8.4 ) $ (617.0 ) Impairments $ (3.5 ) $ (2.1 ) $ (190.5 ) $ (2.1 ) $ — $ (198.2 ) Capital expenditures $ 364.5 $ 39.0 $ 238.1 $ 99.9 $ 6.9 $ 748.4 Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2018 Natural gas sales $ 152.3 $ 140.6 $ 189.7 $ 531.1 $ — $ 1,013.7 NGL sales 0.5 29.0 25.2 2,786.3 — 2,841.0 Crude oil and condensate sales 2,344.1 0.5 85.9 227.1 — 2,657.6 Product sales 2,496.9 170.1 300.8 3,544.5 — 6,512.3 Natural gas sales—related parties (0.3 ) — 2.5 0.3 — 2.5 NGL sales—related parties 454.1 49.4 590.8 47.4 (1,104.3 ) 37.4 Crude oil and condensate sales—related parties — 1.8 0.3 0.2 (1.2 ) 1.1 Product sales—related parties 453.8 51.2 593.6 47.9 (1,105.5 ) 41.0 Gathering and transportation 28.0 146.3 143.2 68.8 — 386.3 Processing 23.8 83.9 128.7 3.3 — 239.7 NGL services — — — 59.6 — 59.6 Crude services 4.2 — 2.8 60.1 — 67.1 Other services 8.7 0.9 0.1 0.9 — 10.6 Midstream services 64.7 231.1 274.8 192.7 — 763.3 Gathering and transportation—related parties — 122.7 80.6 — — 203.3 Processing—related parties — 108.5 48.5 — — 157.0 NGL services—related parties — — — 3.3 (3.3 ) — Crude services—related parties 14.9 — 1.5 — — 16.4 Other services—related parties — 0.5 — — — 0.5 Midstream services—related parties 14.9 231.7 130.6 3.3 (3.3 ) 377.2 Revenue from contracts with customers 3,030.3 684.1 1,299.8 3,788.4 (1,108.8 ) 7,693.8 Cost of sales (2,808.3 ) (199.2 ) (743.6 ) (3,365.7 ) 1,108.8 (6,008.0 ) Operating expenses (96.1 ) (112.7 ) (90.3 ) (154.3 ) — (453.4 ) Gain on derivative activity — — — — 5.2 5.2 Segment profit $ 125.9 $ 372.2 $ 465.9 $ 268.4 $ 5.2 $ 1,237.6 Depreciation and amortization $ (111.0 ) $ (127.9 ) $ (178.8 ) $ (150.9 ) $ (8.7 ) $ (577.3 ) Impairments $ (138.5 ) $ (202.7 ) $ — $ (24.6 ) $ — $ (365.8 ) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 271.7 $ 24.7 $ 493.8 $ 54.4 $ 5.3 $ 849.9 Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2017 Product sales $ 1,344.0 $ 162.5 $ 128.8 $ 2,723.1 $ — $ 4,358.4 Product sales—related parties 357.0 120.5 349.4 39.8 (721.8 ) 144.9 Midstream services 77.5 51.6 155.0 268.2 — 552.3 Midstream services—related parties 18.7 410.4 241.6 151.1 (133.6 ) 688.2 Cost of sales (1,628.5 ) (264.5 ) (523.0 ) (2,800.9 ) 855.4 (4,361.5 ) Operating expenses (85.1 ) (121.8 ) (64.6 ) (147.2 ) — (418.7 ) Loss on derivative activity — — — — (4.2 ) (4.2 ) Segment profit (loss) $ 83.6 $ 358.7 $ 287.2 $ 234.1 $ (4.2 ) $ 959.4 Depreciation and amortization $ (109.9 ) $ (127.0 ) $ (156.3 ) $ (141.7 ) $ (10.4 ) $ (545.3 ) Impairments $ — $ — $ — $ (17.1 ) $ — $ (17.1 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 186.1 $ 18.2 $ 450.1 $ 87.3 $ 26.4 $ 768.1 The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions): Year Ended December 31, 2019 2018 2017 Segment profit $ 1,193.3 $ 1,237.6 $ 959.4 General and administrative expenses (139.2 ) (130.2 ) (123.5 ) Gain (loss) on disposition of assets 1.9 (0.4 ) — Depreciation and amortization (617.0 ) (577.3 ) (545.3 ) Impairments (198.2 ) (365.8 ) (17.1 ) Loss on secured term loan receivable (52.9 ) — — Gain on litigation settlement — — 26.0 Operating income $ 187.9 $ 163.9 $ 299.5 The table below represents information about segment assets (in millions): Segment Identifiable Assets: December 31, 2019 December 31, 2018 Permian $ 2,281.1 $ 2,096.8 North Texas 1,135.8 1,308.2 Oklahoma 3,035.0 3,209.5 Louisiana 2,562.0 2,734.5 Corporate 120.7 222.3 Total identifiable assets $ 9,134.6 $ 9,571.3

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	(15) Quarterly Financial Data (Unaudited) Summarized unaudited quarterly financial data is presented below (in millions, except per unit data): First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Revenues $ 1,779.2 $ 1,710.0 $ 1,408.0 $ 1,155.7 $ 6,052.9 Impairments $ — $ — $ — $ 198.2 $ 198.2 Operating income (loss) $ 110.6 $ 53.4 $ 96.7 $ (72.8 ) $ 187.9 Net income (loss) attributable to ENLK $ 62.8 $ 4.1 $ 42.4 $ (163.6 ) $ (54.3 ) 2018 Revenues $ 1,761.7 $ 1,764.7 $ 2,114.3 $ 2,058.3 $ 7,699.0 Impairments $ — $ — $ 24.6 $ 341.2 $ 365.8 Operating income (loss) $ 106.6 $ 150.1 $ 92.5 $ (185.3 ) $ 163.9 Net income (loss) attributable to ENLK $ 64.3 $ 111.5 $ 48.8 $ (225.1 ) $ (0.5 ) 2017 Revenues $ 1,321.9 $ 1,263.6 $ 1,397.9 $ 1,756.2 $ 5,739.6 Impairments $ 7.0 $ — $ 1.8 $ 8.3 $ 17.1 Operating income $ 57.6 $ 70.4 $ 73.4 $ 98.1 $ 299.5 Net income attributable to ENLK $ 16.7 $ 30.4 $ 27.8 $ 78.8 $ 153.7

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(16) Supplemental Cash Flow Information The following schedule summarizes cash paid for interest and income taxes and non-cash investing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2019 2018 2017 Cash paid for interest (1) $ 218.5 $ 182.6 $ 163.8 Cash paid for income taxes $ 3.9 $ 1.5 $ 4.8 Non-cash investing activities: Non-cash accrual of property and equipment $ (6.5 ) $ 6.8 $ (22.7 ) Discounted secured term loan receivable from contract restructuring $ — $ 47.7 $ — ____________________________ (1) Includes cash paid to ENLC for interest of $62.6 million for the year ended December 31, 2019 .

Other Information

Other Information	12 Months Ended
	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Other Information	(17) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: December 31, 2019 December 31, 2018 Natural gas and NGLs inventory $ 43.4 $ 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 13.5 12.1 Natural gas and NGLs inventory, prepaid expenses, and other $ 56.9 $ 72.8 ____________________________ (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 and was not 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: December 31, 2019 December 31, 2018 Accrued interest $ 32.6 $ 37.3 Accrued wages and benefits, including taxes 25.5 37.2 Accrued ad valorem taxes 28.5 28.1 Capital expenditure accruals 42.4 50.6 Onerous performance obligations — 9.0 Short-term lease liability 21.1 1.5 Suspense producer payments 13.8 34.6 Operating expense accruals 10.8 10.2 Other 27.0 38.2 Other current liabilities $ 201.7 $ 246.7

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with GAAP for complete financial statements. Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources, in connection with which certain reclassifications were made to the financial statements for prior periods to conform to current period presentation. The effect of these reclassifications had no impact on previously reported
Management's Use of Estimates	Management’s Use of Estimates The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.
Revenue Recognition	Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. 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. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales— Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services— Midstream services represent all other revenue generated as a result of performing our midstream services outlined above. Adoption of ASC 606 Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaced previous revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also requires significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Evaluation of Our Contractual Performance Obligations In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include: • promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and • promises to sell a specified volume of commodities to our customers. The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For the year ended December 31, 2018 , the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $671.0 million , or 8.0% , compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows. Changes in Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories: • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations. For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606. Satisfaction of Performance Obligations and Recognition of Revenue While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). 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 year ended December 31, 2019 , we had contractual commitments of $154.0 million under our MVC contracts and recorded $19.7 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2020 $ 262.7 2021 111.0 2022 97.6 2023 92.7 2024 81.3 Thereafter 158.2 Total $ 803.5 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. Contributions in Aid of Construction The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for the year ended December 31, 2018. Disaggregation of Revenue and Presentation of Prior Periods Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. See “ Note 14—Segment Information ” for the revenue disaggregation information included in the segment information table for the years ended December 31, 2019 and 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the years ended December 31, 2019 and 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606. (d) 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. In November 2019, White Star sold its assets and we did not recover any amounts then 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 year ended December 31, 2019, which represents a full write-down of the second lien secured term loan.
Gas Imbalance Accounting	Gas Imbalance Accounting Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. We had imbalance payables of $5.7 million and $12.4 million at December 31, 2019 and 2018 , respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $6.4 million and $10.4 million at December 31, 2019 and 2018 , respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued gas, NGLs, condensate, and crude oil purchases,” respectively, on the consolidated balance sheets.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Income Taxes	Income Taxes Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. We record deferred tax assets and liabilities on a net basis on the consolidated balance sheets, with deferred tax assets included in “Other assets, net” and deferred tax liabilities included in “Deferred tax liability, net.”
Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory	Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory Our inventories of products consist of natural gas, NGLs, crude oil, and condensate. We report these assets at the lower of cost or market value which is determined by using the first-in, first-out method.
Property and Equipment	Property and Equipment Property and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest costs for material projects are capitalized to property and equipment during the period the assets are undergoing preparation for intended use. The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2019 2018 Transmission assets $ 1,376.5 $ 1,329.4 Gathering systems 4,856.5 4,410.5 Gas processing plants 3,862.2 3,590.5 Other property and equipment 188.0 171.7 Construction in process 216.7 312.0 Property and equipment 10,499.9 9,814.1 Accumulated depreciation (3,418.6 ) (2,967.4 ) Property and equipment, net of accumulated depreciation $ 7,081.3 $ 6,846.7 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years Depreciation expense of $490.7 million , $453.8 million , and $418.2 million was recorded for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the statement of operations. For the year ended December 31, 2019, we disposed of assets with a net book value of $12.4 million , and these dispositions primarily related to the sale of certain non-core assets. This decrease in book value was offset by $14.3 million of proceeds from the sale of property, resulting in a $1.9 million gain on disposition of assets in the consolidated statement of operations for the year ended December 31, 2019. For the year ended December 31, 2018, we disposed of assets with a net book value of $2.1 million . These dispositions primarily related to vehicle retirements and retirements due to compressor fire damage. This decrease in book value was offset by $1.7 million of proceeds from the sale of property, resulting in $0.4 million loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2018 . For the year ended December 31, 2017, we disposed of assets with a net book value of $8.4 million , and these dispositions primarily related to the retirement of compressors due to fire damage. This decrease in book value was offset by $6.1 million in insurance settlements and $2.3 million of proceeds from the sale of property, resulting in no gain or loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2017 . Impairment Review . In accordance with ASC 360, Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment annually in the fourth quarter, and whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding: • the future fee-based rate of new business or contract renewals; • the purchase and resale margins on natural gas, NGLs, crude oil, and condensate; • the volume of natural gas, NGLs, crude oil, and condensate available to the asset; • markets available to the asset; • operating expenses; and • future natural gas, NGLs, crude oil, and condensate prices. The amount of availability of natural gas, NGLs, crude oil, and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil, and condensate prices. Projections of natural gas, NGL, crude oil, and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: • changes in general economic conditions in regions in which our markets are located; • the availability and prices of natural gas, NGLs, crude oil, and condensate supply; • our ability to negotiate favorable sales agreements; • the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful; • our dependence on certain significant customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and • competition from other midstream companies, including major energy companies.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is composed of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”).
Equity Method of Accounting	Equity Method of Accounting We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations. We recognized a $31.4 million loss for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV . For additional information, see “ Note 9—Investment in Unconsolidated Affiliates .”
Non-controlling Interests	Non-controlling Interests We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all the assets and liabilities of an investment on our consolidated balance sheets and record non-controlling interest for the portion of the investment that we do not own. We include all of an investment’s results of operations on our consolidated statements of operations and record income attributable to non-controlling interests for the portion of the investment that we do not own.
Goodwill	Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For additional information regarding our assessment of goodwill for impairment, see “ Note 3—Goodwill and Intangible Assets .”
Intangible Assets	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 five to twenty years. For additional information regarding our intangible assets, including our assessment of intangible assets for impairment, see “ Note 3—Goodwill and Intangible Assets
Asset Retirement Obligations	Asset Retirement Obligations We recognize liabilities for retirement obligations associated with our pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Our retirement obligations include estimated environmental remediation costs that arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight-line depreciation method similar to that used for the associated property and equipment.
Other Current Liabilities	Other Current Liabilities Other current liabilities included a liability related to an onerous performance obligation of $9.0 million as of December 31, 2018 . We had one delivery contract that required us to deliver a specified volume of gas each month at an indexed base price that ended June 2019. We realized a loss on the delivery of gas under this contract each month based on current prices. The liability was reduced each month as delivery was made over the life of the contract with an offsetting reduction in purchased gas costs.
Derivatives	Derivatives We use derivative instruments to hedge against changes in cash flows related to product price. We generally determine the fair value of swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet at the fair value of derivative assets or liabilities in accordance with ASC 815. Changes in fair value of derivative instruments are recorded in gain or loss on derivative activity in the period of change. Realized gains and losses on commodity-related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statements of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities. We periodically enter into interest rate swaps in connection with new debt issuances. During the debt issuance process, we are exposed to 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. In order to hedge this variability, we enter into interest rate swaps to effectively lock in the benchmark interest rate at the inception of the swap. In April 2019, we entered into an $850.0 million interest rate swap with ENLC, which mirrored the terms of ENLC’s interest rate swap with a third party, 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 our 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 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 additional information, see “ Note 11—Derivatives .”
Concentrations of Credit Risk	Concentrations of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to significant customers discussed below, since our customers represent a broad and diverse group of energy marketers and end users. The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues. Year Ended December 31, 2019 2018 2017 Devon 10.5 % 10.4 % 14.4 % Dow Hydrocarbons and Resources LLC 10.0 % 11.1 % 11.2 % Marathon Petroleum Corporation 13.8 % 11.5 % (1) ____________________________ (1) Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the year ended December 31, 2017. We continually monitor and review the credit exposure of our counter-parties based on various credit quality indicators and metrics. We obtain letters of credit or other appropriate security when considered necessary to limit the risk of loss. We record reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers and we do not expect to experience significant levels of default on our trade accounts receivable. We had a reserve for uncollectible receivables of $0.5 million and $0.3 million as of December 31, 2019 and 2018 , respectively.
Environmental Costs	Environmental Costs Environmental expenditures are expensed or capitalized depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. For the years ended December 31, 2019 , 2018 , and 2017 , environmental expenditures were not material.
Unit-Based Awards	Unit-Based Awards We recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718, Compensation—Stock Compensation (“ASC 718”). Unit-based compensation associated with ENLC’s unit-based compensation plans awarded to directors, officers, and employees of our general partner are recorded by us since ENLC has no substantial or managed operating activities other than its interests in ENLK. For additional information, see “ Note 10—Employee Incentive Plans .”
Commitments and Contingencies	Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with a loss contingency are expensed as incurred. For additional information, see “ Note 13—Commitments and Contingencies .”
Debt Issuance Costs	Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized into interest expense using the straight-line method over the term of the related debt. Gains or losses on debt repurchases, redemptions, and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $29.8 million and $24.3 million as of December 31, 2019 and 2018 , respectively, are included in “Long-term debt” or “Current maturities of long-term debt,” as applicable, on the consolidated balance sheets as a direct reduction from the carrying amount of the debt.
Redeemable Non-Controlling Interest	Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require us to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interest is not considered to be a component of partners’ equity and is reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions).
Adopted Accounting Standards and Accounting Standards to be Adopted in Future Periods	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 .” (y) 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 statements of operations, rather than “Depreciation and amortization.” We will adopt ASU 2018-15 prospectively effective January 1, 2020.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 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 year ended December 31, 2019 , we had contractual commitments of $154.0 million under our MVC contracts and recorded $19.7 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2020 $ 262.7 2021 111.0 2022 97.6 2023 92.7 2024 81.3 Thereafter 158.2 Total $ 803.5 ____________________________ (1) Amounts do not represent expected shortfall under these commitments.
Property, Plant and Equipment	The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2019 2018 Transmission assets $ 1,376.5 $ 1,329.4 Gathering systems 4,856.5 4,410.5 Gas processing plants 3,862.2 3,590.5 Other property and equipment 188.0 171.7 Construction in process 216.7 312.0 Property and equipment 10,499.9 9,814.1 Accumulated depreciation (3,418.6 ) (2,967.4 ) Property and equipment, net of accumulated depreciation $ 7,081.3 $ 6,846.7 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years
Schedules of Concentration of Risk, by Risk Factor	The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues. Year Ended December 31, 2019 2018 2017 Devon 10.5 % 10.4 % 14.4 % Dow Hydrocarbons and Resources LLC 10.0 % 11.1 % 11.2 % Marathon Petroleum Corporation 13.8 % 11.5 % (1) ____________________________ (1) Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the year ended December 31, 2017.

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The table below provides a summary of our change in carrying amount of goodwill by segment (in millions) for the years ended December 31, 2019 and 2018, by assigned reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amounts of goodwill. Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2019 Balance, beginning of period $ — $ — $ 190.3 $ — $ — $ 190.3 Impairment — — (190.3 ) — — (190.3 ) Balance, end of period $ — $ — $ — $ — $ — $ — Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2018 Balance, beginning of period $ 29.3 $ 202.7 $ 190.3 $ — $ — $ 422.3 Impairment (29.3 ) (202.7 ) — — — (232.0 ) Balance, end of period $ — $ — $ 190.3 $ — $ — $ 190.3
Summary of Change in Carrying Value	The following table represents our change in carrying value of intangible assets for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2019 Customer relationships, beginning of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Amortization expense — (123.7 ) (123.7 ) Customer relationships, end of period $ 1,795.8 $ (545.9 ) $ 1,249.9 Year Ended December 31, 2018 Customer relationships, beginning of period $ 1,795.8 $ (298.7 ) $ 1,497.1 Amortization expense — (123.5 ) (123.5 ) Customer relationships, end of period $ 1,795.8 $ (422.2 ) $ 1,373.6 Year Ended December 31, 2017 Customer relationships, beginning of period $ 1,795.8 $ (171.6 ) $ 1,624.2 Amortization expense — (127.1 ) (127.1 ) Customer relationships, end of period $ 1,795.8 $ (298.7 ) $ 1,497.1
Summary of Estimated Aggregate Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 $ 123.7 2021 123.7 2022 123.7 2023 123.6 2024 123.4 Thereafter 631.8 Total $ 1,249.9

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Assets and Liabilities, Lessee	Lease balances are recorded on the consolidated balance sheets as follows (in millions): December 31, 2019 Operating leases: Other assets, net $ 80.4 Other current liabilities $ 21.1 Other long-term liabilities $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 10.6 years Weighted-average discount rate—Operating leases 5.1 %
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): Year Ended December 31, 2019 Finance lease expense: Amortization of right-of-use asset $ 5.2 Interest on lease liability 0.1 Operating lease expense: Long-term operating lease expense 28.7 Short-term lease expense 32.0 Variable lease expense 7.7 Total lease expense $ 68.4 Other information about our leases is presented below (in millions): Year Ended December 31, 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ 1.2 Cash payments for operating leases included in cash flows from operating activities $ 29.8 Right-of-use assets obtained in exchange for operating lease liabilities $ 104.1
Lessee, Operating Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of December 31, 2019 (in millions): Total 2020 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 141.2 $ 25.0 $ 18.7 $ 11.7 $ 9.7 $ 9.1 $ 67.0 Reduction due to present value (38.2 ) (4.7 ) (3.9 ) (3.4 ) (3.1 ) (2.7 ) (20.4 ) Operating lease liability $ 103.0 $ 20.3 $ 14.8 $ 8.3 $ 6.6 $ 6.4 $ 46.6

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As of December 31, 2019 and 2018 , long-term debt consisted of the following (in millions): December 31, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Related party debt $ 1,700.0 $ — $ 1,700.0 $ — $ — $ — Term Loan due 2021 (1) — — — 850.0 — 850.0 2.70% Senior unsecured notes due 2019 (2) — — — 400.0 — 400.0 4.40% Senior unsecured notes due 2024 550.0 1.5 551.5 550.0 1.8 551.8 4.15% Senior unsecured notes due 2025 750.0 (0.7 ) 749.3 750.0 (0.9 ) 749.1 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.5 ) 499.5 5.60% Senior unsecured notes due 2044 350.0 (0.2 ) 349.8 350.0 (0.2 ) 349.8 5.05% Senior unsecured notes due 2045 450.0 (5.9 ) 444.1 450.0 (6.2 ) 443.8 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 $ 4,800.0 $ (5.9 ) 4,794.1 $ 4,350.0 $ (6.1 ) 4,343.9 Debt issuance cost (3) (29.8 ) (24.3 ) Less: Current maturities of long-term debt (2) — (399.8 ) Long-term debt, net of unamortized issuance cost $ 4,764.3 $ 3,919.8 ____________________________ (1) In December 2018, ENLK entered into an $850.0 million , three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2018 . In connection with the closing of the Merger, the Term Loan was assumed by ENLC, and we became a guarantor of the Term Loan. (2) The 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. (3) Net of accumulated amortization of $10.9 million and $15.3 million at December 31, 2019 and 2018 , respectively. See applicable redemption provision terms below: Issuance Maturity Date of Notes Early Redemption Date Basis Point Premium 2024 Notes April 1, 2024 Prior to January 1, 2024 25 Basis Points 2025 Notes June 1, 2025 Prior to March 1, 2025 30 Basis Points 2026 Notes July 15, 2026 Prior to April 15, 2026 50 Basis Points 2029 Notes June 1, 2029 Prior to March 1, 2029 50 Basis Points 2044 Notes April 1, 2044 Prior to October 1, 2043 30 Basis Points 2045 Notes April 1, 2045 Prior to October 1, 2044 30 Basis Points 2047 Notes June 1, 2047 Prior to June 1, 2047 40 Basis Points
Schedule of Maturities of Long-term Debt	Maturities for the long-term debt as of December 31, 2019 are as follows (in millions): 2020 $ — 2021 850.0 2022 — 2023 — 2024 900.0 Thereafter 3,050.0 Subtotal 4,800.0 Less: net discount (5.9 ) Less: debt issuance cost (29.8 ) Long-term debt, net of unamortized issuance cost $ 4,764.3

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (expense) are as follows (in millions): Year Ended December 31, 2019 2018 2017 Current income tax expense $ (0.4 ) $ (1.8 ) $ (2.6 ) Deferred tax benefit (expense) (2.1 ) 3.9 26.6 Total income tax benefit (expense) $ (2.5 ) $ 2.1 $ 24.0

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2019
Partners' Capital Notes [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2019 , 2018 , and 2017 is provided below: Declaration period Distribution Cash distribution Date paid/payable 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019 Second Quarter of 2019 148,257 $ 17.1 August 13, 2019 Third Quarter of 2019 148,627 $ 17.1 November 13, 2019 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 Third Quarter of 2018 422,720 $ 16.4 November 13, 2018 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 2017 First Quarter of 2017 1,154,147 $ — May 12, 2017 Second Quarter of 2017 1,178,672 $ — August 11, 2017 Third Quarter of 2017 410,681 $ 15.9 November 13, 2017 Fourth Quarter of 2017 413,658 $ 16.1 February 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 2018 First Quarter of 2018 $ 0.390 May 14, 2018 Second Quarter of 2018 $ 0.390 August 13, 2018 Third Quarter of 2018 $ 0.390 November 13, 2018 Fourth Quarter of 2018 $ 0.390 February 13, 2019 2017 First Quarter of 2017 $ 0.390 May 12, 2017 Second Quarter of 2017 $ 0.390 August 11, 2017 Third Quarter of 2017 $ 0.390 November 13, 2017 Fourth Quarter of 2017 $ 0.390 February 13, 2018
Incentive Distributions	For the years ended December 31, 2019 , 2018 , and 2017 , the net income allocated to the general partner is as follows (in millions): Year Ended December 31, 2019 2018 2017 Income allocation for incentive distributions $ — $ 59.5 $ 58.9 Unit-based compensation attributable to ENLC’s restricted and performance units (37.0 ) (20.3 ) (21.0 ) General partner share of net income (loss) (1.4 ) (0.6 ) 0.4 General partner interest in EOGP acquisition 2.4 27.5 4.8 General partner interest in net income (loss) $ (36.0 ) $ 66.1 $ 43.1

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2019 2018 2017 GCF Distributions $ 19.2 $ 22.3 $ 12.7 Equity in income $ 16.5 $ 15.8 $ 12.6 HEP Equity in loss (1) $ — $ — $ (3.4 ) Cedar Cove JV Contributions $ — $ 0.1 $ 12.6 Distributions $ 1.0 $ 0.4 $ 0.8 Equity in income (loss) (2) $ (33.3 ) $ (2.5 ) $ 0.4 Total Contributions $ — $ 0.1 $ 12.6 Distributions $ 20.2 $ 22.7 $ 13.5 Equity in income (loss) (1)(2) $ (16.8 ) $ 13.3 $ 9.6 ___________________________ (1) Includes a loss of $3.4 million for the year ended December 31, 2017 related to the sale of our HEP interests . In March 2017, we sold an approximate 31.0% ownership interest in HEP for aggregate net proceeds of $189.7 million . (2) Includes a loss of $31.4 million for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV . The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2019 and 2018 (in millions): December 31, 2019 December 31, 2018 GCF $ 39.2 $ 41.9 Cedar Cove JV 3.9 38.2 Total investment in unconsolidated affiliates $ 43.1 $ 80.1

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 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): Year Ended December 31, 2019 2018 2017 Cost of unit-based compensation charged to general and administrative expense $ 32.5 $ 30.0 $ 37.1 Cost of unit-based compensation charged to operating expense 6.7 10.8 10.7 Total unit-based compensation expense $ 39.2 $ 40.8 $ 47.8
Summary of Restricted Incentive Unit Activity	A summary of the restricted incentive unit activity for the year ended December 31, 2019 is provided below: Year Ended December 31, 2019 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) 2,027,653 11.09 Vested (1)(2) (1,886,905 ) 12.06 Forfeited (606,276 ) 13.85 Converted from ENLK (3) 2,103,266 14.01 Non-vested, end of period 4,063,605 $ 13.85 Aggregate intrinsic value, end of period (in millions) $ 24.9 ____________________________ (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 626,133 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 unit activity for the year ended December 31, 2019 is provided below: Year Ended December 31, 2019 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 years ended December 31, 2019 , 2018 , and 2017 is provided below (in millions): Year Ended December 31, EnLink Midstream, LLC Restricted Incentive Units: 2019 2018 2017 Aggregate intrinsic value of units vested $ 17.3 $ 12.8 $ 15.3 Fair value of units vested $ 22.8 $ 16.5 $ 22.2 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 years ended December 31, 2019 , 2018 , and 2017 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2019 2018 2017 Aggregate intrinsic value of units vested $ 8.0 $ 13.1 $ 16.6 Fair value of units vested $ 7.2 $ 16.4 $ 22.6
Summary of Grant-Date Fair Values	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 Vesting percentage 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 Manager 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 Manager 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 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 (or for outstanding performance units granted prior to the Merger, ENLC and ENLK) 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: October 2019 June 2019 March 2019 March 2018 March 2017 Grant-date fair value $ 7.29 $ 9.92 $ 13.10 $ 21.63 $ 28.77 Beginning TSR price $ 7.42 $ 9.84 $ 10.92 $ 16.55 $ 18.29 Risk-free interest rate 1.44 % 1.72 % 2.42 % 2.38 % 1.62 % Volatility factor 35.00 % 33.50 % 33.86 % 51.36 % 52.07 % Distribution yield 10.1 % 11.5 % 9.7 % 6.7 % 5.4 % EnLink Midstream Partners, LP Performance Units: March 2018 March 2017 Grant-date fair value $ 19.24 $ 25.73 Beginning TSR price $ 15.44 $ 17.55 Risk-free interest rate 2.38 % 1.62 % Volatility factor 43.85 % 43.94 % Distribution yield 10.5 % 8.7 %
Summary of Performance Units	The following table presents a summary of the performance units: Year Ended December 31, 2019 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 years ended December 31, 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 as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. No performance units vested for the year ended December 31, 2017. Year Ended December 31, EnLink Midstream Partners, LP Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 2.1 $ 5.0 Fair value of units vested $ 1.7 $ 7.7 The following table presents a summary of the performance units: Year Ended December 31, 2019 EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 418,149 $ 19.15 Granted 1,202,105 11.73 Vested (1) (374,745 ) 21.08 Forfeited (261,451 ) 15.68 Converted from ENLK (2) 333,798 25.84 Non-vested, end of period 1,317,856 $ 14.22 Aggregate intrinsic value, end of period (in millions) $ 8.1 ____________________________ (1) Vested units included 146,218 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 years ended December 31, 2019 and 2018 is provided below (in millions). No performance units vested for the year ended December 31, 2017. Year Ended December 31, EnLink Midstream, LLC Performance Units: 2019 2018 Aggregate intrinsic value of units vested $ 3.4 $ 4.7 Fair value of units vested $ 7.9 $ 7.7

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): December 31, 2019 December 31, 2018 Fair value of derivative assets—current $ 12.9 $ 28.6 Fair value of derivative assets—long-term 4.3 4.1 Fair value of derivative liabilities—current (8.8 ) (21.8 ) Fair value of derivative liabilities—long-term — (2.4 ) Net fair value of derivatives $ 8.4 $ 8.5 The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): December 31, 2019 Fair value of derivative liabilities—current $ (5.6 ) Fair value of derivative liabilities—long-term (6.8 ) Net fair value of derivatives $ (12.4 )
Components of Gain (Loss)	The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Year Ended December 31, 2019 2018 2017 Change in fair value of derivatives $ (0.1 ) $ 10.1 $ 4.7 Realized gain (loss) on derivatives 14.5 (4.9 ) (8.9 ) Gain (loss) on derivative activity $ 14.4 $ 5.2 $ (4.2 )
Summary of Notional Volumes and Fair Value of 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 December 31, 2019 (in millions). The remaining term of the contracts extend no later than December 2022 . December 31, 2019 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (64.0 ) $ 1.7 NGL (long contracts) Swaps Gallons 11.7 (0.5 ) Natural gas (short contracts) Swaps MMBtu (4.7 ) 1.0 Natural gas (long contracts) Swaps MMBtu 3.7 (0.4 ) Crude and condensate (short contracts) Swaps MMbbls (12.8 ) (1.0 ) Crude and condensate (long contracts) Swaps MMbbls 2.0 7.6 Total fair value of derivatives $ 8.4

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2019 December 31, 2018 Interest rate swaps (1) $ (12.4 ) $ — Commodity swaps (2) $ 8.4 $ 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	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): December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 4,764.3 $ 4,444.2 $ 4,319.6 $ 3,953.6 Obligations under financing lease $ — $ — $ 2.5 $ 2.2 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 the long-term debt is reduced by debt issuance costs of $29.8 million and $24.3 million at December 31, 2019 and 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 and was not 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)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Summarized Financial Information	Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2019 Natural gas sales $ 94.3 $ 129.3 $ 236.4 $ 416.6 $ — $ 876.6 NGL sales 0.9 30.9 19.6 1,725.6 — 1,777.0 Crude oil and condensate sales 1,975.0 — 109.6 291.9 — 2,376.5 Product sales 2,070.2 160.2 365.6 2,434.1 — 5,030.1 Natural gas sales—related parties 0.4 — — — (0.4 ) — NGL sales—related parties 347.7 94.8 421.1 25.7 (889.3 ) — Crude oil and condensate sales—related parties 13.5 5.5 — 1.7 (20.7 ) — Product sales—related parties 361.6 100.3 421.1 27.4 (910.4 ) — Gathering and transportation 48.8 196.4 234.5 58.3 — 538.0 Processing 30.5 143.0 138.2 3.2 — 314.9 NGL services — 0.1 — 50.6 — 50.7 Crude services 19.2 — 19.8 51.9 — 90.9 Other services 12.0 1.1 0.1 0.7 — 13.9 Midstream services 110.5 340.6 392.6 164.7 — 1,008.4 NGL services—related parties — — — (3.4 ) 3.4 — Crude services—related parties — — 1.8 — (1.8 ) — Midstream services—related parties — — 1.8 (3.4 ) 1.6 — Revenue from contracts with customers 2,542.3 601.1 1,181.1 2,622.8 (908.8 ) 6,038.5 Cost of sales (2,283.9 ) (208.8 ) (627.0 ) (2,181.6 ) 908.8 (4,392.5 ) Operating expenses (112.9 ) (102.9 ) (104.0 ) (147.3 ) — (467.1 ) Gain on derivative activity — — — — 14.4 14.4 Segment profit $ 145.5 $ 289.4 $ 450.1 $ 293.9 $ 14.4 $ 1,193.3 Depreciation and amortization $ (119.8 ) $ (139.8 ) $ (194.9 ) $ (154.1 ) $ (8.4 ) $ (617.0 ) Impairments $ (3.5 ) $ (2.1 ) $ (190.5 ) $ (2.1 ) $ — $ (198.2 ) Capital expenditures $ 364.5 $ 39.0 $ 238.1 $ 99.9 $ 6.9 $ 748.4 Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2018 Natural gas sales $ 152.3 $ 140.6 $ 189.7 $ 531.1 $ — $ 1,013.7 NGL sales 0.5 29.0 25.2 2,786.3 — 2,841.0 Crude oil and condensate sales 2,344.1 0.5 85.9 227.1 — 2,657.6 Product sales 2,496.9 170.1 300.8 3,544.5 — 6,512.3 Natural gas sales—related parties (0.3 ) — 2.5 0.3 — 2.5 NGL sales—related parties 454.1 49.4 590.8 47.4 (1,104.3 ) 37.4 Crude oil and condensate sales—related parties — 1.8 0.3 0.2 (1.2 ) 1.1 Product sales—related parties 453.8 51.2 593.6 47.9 (1,105.5 ) 41.0 Gathering and transportation 28.0 146.3 143.2 68.8 — 386.3 Processing 23.8 83.9 128.7 3.3 — 239.7 NGL services — — — 59.6 — 59.6 Crude services 4.2 — 2.8 60.1 — 67.1 Other services 8.7 0.9 0.1 0.9 — 10.6 Midstream services 64.7 231.1 274.8 192.7 — 763.3 Gathering and transportation—related parties — 122.7 80.6 — — 203.3 Processing—related parties — 108.5 48.5 — — 157.0 NGL services—related parties — — — 3.3 (3.3 ) — Crude services—related parties 14.9 — 1.5 — — 16.4 Other services—related parties — 0.5 — — — 0.5 Midstream services—related parties 14.9 231.7 130.6 3.3 (3.3 ) 377.2 Revenue from contracts with customers 3,030.3 684.1 1,299.8 3,788.4 (1,108.8 ) 7,693.8 Cost of sales (2,808.3 ) (199.2 ) (743.6 ) (3,365.7 ) 1,108.8 (6,008.0 ) Operating expenses (96.1 ) (112.7 ) (90.3 ) (154.3 ) — (453.4 ) Gain on derivative activity — — — — 5.2 5.2 Segment profit $ 125.9 $ 372.2 $ 465.9 $ 268.4 $ 5.2 $ 1,237.6 Depreciation and amortization $ (111.0 ) $ (127.9 ) $ (178.8 ) $ (150.9 ) $ (8.7 ) $ (577.3 ) Impairments $ (138.5 ) $ (202.7 ) $ — $ (24.6 ) $ — $ (365.8 ) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 271.7 $ 24.7 $ 493.8 $ 54.4 $ 5.3 $ 849.9 Permian North Texas Oklahoma Louisiana Corporate Totals Year Ended December 31, 2017 Product sales $ 1,344.0 $ 162.5 $ 128.8 $ 2,723.1 $ — $ 4,358.4 Product sales—related parties 357.0 120.5 349.4 39.8 (721.8 ) 144.9 Midstream services 77.5 51.6 155.0 268.2 — 552.3 Midstream services—related parties 18.7 410.4 241.6 151.1 (133.6 ) 688.2 Cost of sales (1,628.5 ) (264.5 ) (523.0 ) (2,800.9 ) 855.4 (4,361.5 ) Operating expenses (85.1 ) (121.8 ) (64.6 ) (147.2 ) — (418.7 ) Loss on derivative activity — — — — (4.2 ) (4.2 ) Segment profit (loss) $ 83.6 $ 358.7 $ 287.2 $ 234.1 $ (4.2 ) $ 959.4 Depreciation and amortization $ (109.9 ) $ (127.0 ) $ (156.3 ) $ (141.7 ) $ (10.4 ) $ (545.3 ) Impairments $ — $ — $ — $ (17.1 ) $ — $ (17.1 ) Goodwill $ 29.3 $ 202.7 $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 186.1 $ 18.2 $ 450.1 $ 87.3 $ 26.4 $ 768.1
Reconciliation of Profits Reported to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions): Year Ended December 31, 2019 2018 2017 Segment profit $ 1,193.3 $ 1,237.6 $ 959.4 General and administrative expenses (139.2 ) (130.2 ) (123.5 ) Gain (loss) on disposition of assets 1.9 (0.4 ) — Depreciation and amortization (617.0 ) (577.3 ) (545.3 ) Impairments (198.2 ) (365.8 ) (17.1 ) Loss on secured term loan receivable (52.9 ) — — Gain on litigation settlement — — 26.0 Operating income $ 187.9 $ 163.9 $ 299.5
Reconciliation of Assets from Segment to Consolidated	The table below represents information about segment assets (in millions): Segment Identifiable Assets: December 31, 2019 December 31, 2018 Permian $ 2,281.1 $ 2,096.8 North Texas 1,135.8 1,308.2 Oklahoma 3,035.0 3,209.5 Louisiana 2,562.0 2,734.5 Corporate 120.7 222.3 Total identifiable assets $ 9,134.6 $ 9,571.3

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Summarized unaudited quarterly financial data is presented below (in millions, except per unit data): First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Revenues $ 1,779.2 $ 1,710.0 $ 1,408.0 $ 1,155.7 $ 6,052.9 Impairments $ — $ — $ — $ 198.2 $ 198.2 Operating income (loss) $ 110.6 $ 53.4 $ 96.7 $ (72.8 ) $ 187.9 Net income (loss) attributable to ENLK $ 62.8 $ 4.1 $ 42.4 $ (163.6 ) $ (54.3 ) 2018 Revenues $ 1,761.7 $ 1,764.7 $ 2,114.3 $ 2,058.3 $ 7,699.0 Impairments $ — $ — $ 24.6 $ 341.2 $ 365.8 Operating income (loss) $ 106.6 $ 150.1 $ 92.5 $ (185.3 ) $ 163.9 Net income (loss) attributable to ENLK $ 64.3 $ 111.5 $ 48.8 $ (225.1 ) $ (0.5 ) 2017 Revenues $ 1,321.9 $ 1,263.6 $ 1,397.9 $ 1,756.2 $ 5,739.6 Impairments $ 7.0 $ — $ 1.8 $ 8.3 $ 17.1 Operating income $ 57.6 $ 70.4 $ 73.4 $ 98.1 $ 299.5 Net income attributable to ENLK $ 16.7 $ 30.4 $ 27.8 $ 78.8 $ 153.7

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Summary of Non-Cash Financing Activities	The following schedule summarizes cash paid for interest and income taxes and non-cash investing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2019 2018 2017 Cash paid for interest (1) $ 218.5 $ 182.6 $ 163.8 Cash paid for income taxes $ 3.9 $ 1.5 $ 4.8 Non-cash investing activities: Non-cash accrual of property and equipment $ (6.5 ) $ 6.8 $ (22.7 ) Discounted secured term loan receivable from contract restructuring $ — $ 47.7 $ — ____________________________ (1) Includes cash paid to ENLC for interest of $62.6 million for the year ended December 31, 2019 .

Other Information (Tables)

Other Information (Tables)	12 Months Ended
	Dec. 31, 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): Other current assets: December 31, 2019 December 31, 2018 Natural gas and NGLs inventory $ 43.4 $ 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 13.5 12.1 Natural gas and NGLs inventory, prepaid expenses, and other $ 56.9 $ 72.8 ____________________________ (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 and was not 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: December 31, 2019 December 31, 2018 Accrued interest $ 32.6 $ 37.3 Accrued wages and benefits, including taxes 25.5 37.2 Accrued ad valorem taxes 28.5 28.1 Capital expenditure accruals 42.4 50.6 Onerous performance obligations — 9.0 Short-term lease liability 21.1 1.5 Suspense producer payments 13.8 34.6 Operating expense accruals 10.8 10.2 Other 27.0 38.2 Other current liabilities $ 201.7 $ 246.7

Organization and Summary of S_2

Organization and Summary of Significant Agreements (Details) mi in Thousands, bbl in Thousands	Jan. 31, 2019shares	Jan. 25, 2019	Jul. 18, 2018	Dec. 31, 2019Bcf / dplantfractionatormibbl	Jan. 07, 2016
Business Acquisition [Line Items]
Partners capital, common units conversion ratio		1.15
Number of miles of pipeline | mi				12
Number of natural gas processing plants | plant				21
Amount of processing capacity (in billions of cubic feet per day) | Bcf / d				5.3
Number of fractionators | fractionator				7
Capacity of fractionators per day, in barrels | bbl				290
EOGP
Business Acquisition [Line Items]
Acquired voting interest					83.90%
EOGP | ENLC
Business Acquisition [Line Items]
Acquired voting interest					16.10%
ENLC
Business Acquisition [Line Items]
Shares issued for transfer of ownership (in shares) | shares	55,827,221
ENLC | GIP Stetson II
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests			63.80%
TOMPC LLC and TOM-STACK, LLC | EOGP
Business Acquisition [Line Items]
Acquired voting interest					100.00%
EOGP | ENLC
Business Acquisition [Line Items]
Noncontrolling interest percentage	16.10%
EnLink Midstream Partners GP, LLC | GIP Stetson I
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests			100.00%
EnLink Midstream Partners, LP | GIP Stetson I
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests			23.10%

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details)	May 31, 2019USD ($)	Oct. 31, 2019USD ($)	May 31, 2019USD ($)	Dec. 31, 2019USD ($)contract	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Apr. 30, 2019USD ($)	Jan. 01, 2019USD ($)	May 31, 2017USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Decrease in revenue from contracts with customers				$ (6,038,500,000)	$ (7,693,800,000)
Financing receivable, gross	$ 58,000,000		$ 58,000,000
Loss on secured term loan receivable				52,900,000	0	$ 0
Gas imbalance payables				5,700,000	12,400,000
Gas imbalance receivables				6,400,000	10,400,000
Depreciation				490,700,000	453,800,000	418,200,000
Retired or sold net property, plant and equipment				12,400,000	2,100,000	8,400,000
Expected proceeds from insurance settlements						6,100,000
Proceeds from sale of productive assets				14,300,000	1,700,000	2,300,000
Gain (loss) on productive assets				1,900,000	(400,000)	0
Impairment charge on property, plant, and equipment				$ 7,900,000		17,100,000
Provision for loss on contracts					9,000,000
Number of contracts | contract				1
Derivative, notional amount							$ 850,000,000
Derivative, fixed interest rate							2.27825%
Accumulated other comprehensive loss				$ 14,500,000	2,100,000				$ 2,200,000
Allowance for bad debt				500,000	300,000
Environmental remediation expense				0	0	$ 0
Debt issuance costs, noncurrent, net				29,800,000	24,300,000
Lease liability (less than)				103,000,000
Other assets, net				$ 80,400,000
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Lease liability (less than)								$ 97,600,000
Other assets, net								75,300,000
Other liabilities								$ 22,600,000
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Amortization period				5 years
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Amortization period				20 years
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Decrease in revenue from contracts with customers					$ 671,000,000
Percentage decrease in revenue from contracts with customers					8.00%
Louisiana
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charge on property, plant, and equipment					$ 24,600,000
Crude and Condensate
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charge on property, plant, and equipment					$ 109,200,000
Cedar Cove Midstream, LLC [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charge on property, plant, and equipment				$ 31,400,000
Delaware Basin JV | NPG
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncontrolling interest percentage				49.90%
Ascension JV | Marathon Petroleum Corporation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncontrolling interest percentage				50.00%
Minimum Volume Contract
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability				$ 154,000,000
Contracts with customer, revenue recognition				$ 19,700,000
White Star
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt instrument, periodic payment	$ 19,500,000	$ 10,750,000	$ 9,750,000

Significant Accounting Polici_5

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 803.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 262.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 111
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 97.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 92.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 81.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 158.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period

Significant Accounting Polici_6

Significant Accounting Policies - Components of Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property and equipment	$ 10,499.9	$ 9,814.1
Accumulated depreciation	(3,418.6)	(2,967.4)
Property and equipment, net of accumulated depreciation	7,081.3	6,846.7
Transmission assets
Property, Plant and Equipment [Line Items]
Property and equipment	$ 1,376.5	1,329.4
Transmission assets | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years
Transmission assets | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	25 years
Gathering systems
Property, Plant and Equipment [Line Items]
Property and equipment	$ 4,856.5	4,410.5
Gathering systems | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years
Gathering systems | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	25 years
Gas processing plants
Property, Plant and Equipment [Line Items]
Property and equipment	$ 3,862.2	3,590.5
Gas processing plants | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years
Gas processing plants | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	25 years
Other property and equipment
Property, Plant and Equipment [Line Items]
Property and equipment	$ 188	171.7
Other property and equipment | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	3 years
Other property and equipment | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	15 years
Construction in process
Property, Plant and Equipment [Line Items]
Property and equipment	$ 216.7	$ 312

Significant Accounting Polici_7

Significant Accounting Policies - Customer Concentration Risk (Details) - Sales Revenue, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Devon
Concentration Risk [Line Items]
Concentration risk	10.50%	10.40%	14.40%
Dow Hydrocarbons and Resources LLC
Concentration Risk [Line Items]
Concentration risk	10.00%	11.10%	11.20%
Marathon Petroleum Corporation
Concentration Risk [Line Items]
Concentration risk	13.80%	11.50%

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Changes in Carrying Value of Goodwill (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Roll Forward]
Balance, beginning of period				$ 190,300,000	$ 422,300,000
Impairment	$ (190,300,000)	$ 0		(190,300,000)	(232,000,000)	$ 0
Balance, end of period	0		$ 190,300,000	0	190,300,000	422,300,000
Operating Segments | Permian
Goodwill [Roll Forward]
Balance, beginning of period				0	29,300,000
Impairment			(29,300,000)	0
Balance, end of period	0		0	0	0	29,300,000
Operating Segments | North Texas
Goodwill [Roll Forward]
Balance, beginning of period				0	202,700,000
Impairment			(202,700,000)	0
Balance, end of period	0		0	0	0	202,700,000
Operating Segments | Oklahoma
Goodwill [Roll Forward]
Balance, beginning of period				190,300,000	190,300,000
Impairment				(190,300,000)	0
Balance, end of period	0		190,300,000	0	190,300,000	190,300,000
Operating Segments | Louisiana
Goodwill [Roll Forward]
Balance, beginning of period				0	0
Impairment				0	0
Balance, end of period	0		0	0	0	0
Corporate
Goodwill [Roll Forward]
Balance, beginning of period				0	0
Impairment				0	0
Balance, end of period	$ 0		$ 0	$ 0	$ 0	$ 0

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Narrative (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill
Goodwill impairment loss	$ 190,300,000	$ 0		$ 190,300,000	$ 232,000,000	$ 0
Impairment of intangible assets				0	0	0
Amortization expense				$ 123,700,000	$ 123,500,000	$ 127,100,000
Minimum
Goodwill
Amortization period				5 years
Maximum
Goodwill
Amortization period				20 years
Weighted average
Goodwill
Amortization period				15 years
Operating Segments | Permian
Goodwill
Goodwill impairment loss			$ 29,300,000	$ 0
Operating Segments | North Texas
Goodwill
Goodwill impairment loss			$ 202,700,000	$ 0

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Changes in Carrying Value of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Finite-lived Intangible Assets [Roll Forward]
Accumulated amortization, beginning balance	$ (422.2)
Amortization expense	(123.7)	$ (123.5)	$ (127.1)
Accumulated amortization, ending balance	(545.9)	(422.2)
Net carrying amount, ending balance	1,249.9
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance	1,795.8	1,795.8	1,795.8
Accumulated amortization, beginning balance	(422.2)	(298.7)	(171.6)
Net carrying amount, beginning balance	1,373.6	1,497.1	1,624.2
Amortization expense	(123.7)	(123.5)	(127.1)
Gross carrying amount, ending balance	1,795.8	1,795.8	1,795.8
Accumulated amortization, ending balance	(545.9)	(422.2)	(298.7)
Net carrying amount, ending balance	$ 1,249.9	$ 1,373.6	$ 1,497.1

Goodwill and Intangible Asset_5

Goodwill and Intangible Assets - Amortization Expense (Details) $ in Millions	Dec. 31, 2019USD ($)
Summary of estimated amortization expense
2020	$ 123.7
2021	123.7
2022	123.7
2023	123.6
2024	123.4
Thereafter	631.8
Total	$ 1,249.9

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)		Jan. 31, 2019	Jul. 18, 2018	Jan. 31, 2016	Jun. 30, 2014	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jul. 18, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019	Jan. 07, 2016
Related Party Transaction
Accounts payable to related party						$ 1,100,000				$ 4,300,000									$ 1,100,000	$ 4,300,000
Product sales																			6,038,500,000	7,693,800,000
Revenues						1,155,700,000	$ 1,408,000,000	$ 1,710,000,000	$ 1,779,200,000	2,058,300,000	$ 2,114,300,000	$ 1,764,700,000	$ 1,761,700,000	$ 1,756,200,000	$ 1,397,900,000	$ 1,263,600,000	$ 1,321,900,000		6,052,900,000	7,699,000,000	$ 5,739,600,000
Cost of sales	[1]																		4,392,500,000	6,008,000,000	4,361,500,000
Reimbursed Capital Expenditures
Related Party Transaction
Transactions with related party																				26,600,000	48,400,000
Cedar Cove Joint Venture
Related Party Transaction
Revenues																				500,000	5,400,000
Cost of sales																			21,700,000	44,100,000	30,600,000
Tax Sharing Agreement
Related Party Transaction
Transactions with related party																		$ 400,000			1,200,000
EOGP
Related Party Transaction
Acquired voting interest																							83.90%
ENLC
Related Party Transaction
Reimbursement revenue																				2,500,000	2,400,000
Accounts receivable, related parties						18,100,000				1,400,000									18,100,000	1,400,000
Devon
Related Party Transaction
Revenue from related parties																		66,600,000			78,000,000
Devon | Minimum Volume Contract
Related Party Transaction
Revenue from purchased oil and gas																		50,800,000			81,900,000
Devon | EOGP
Related Party Transaction
Minimum volume commitment				4 years
Term of contract				15 years
Revenue from related parties																		77,600,000			100,400,000
Devon | VEX Pipeline
Related Party Transaction
Term of contract					5 years
Revenue from related parties																		3,500,000			17,800,000
Acacia
Related Party Transaction
Revenue from related parties																		4,900,000			$ 13,800,000
Cedar Cove Joint Venture
Related Party Transaction
Accounts receivable balance						0				700,000									0	700,000
Accounts payable to related party						$ 1,100,000				$ 4,300,000									$ 1,100,000	$ 4,300,000
Sales Revenue, Net | Customer Concentration Risk | Devon
Related Party Transaction
Concentration risk																				5.40%	14.40%
ENLC
Related Party Transaction
Stated interest rate						5.375%													5.375%
ENLC | EOGP
Related Party Transaction
Acquired voting interest																							16.10%
Devon | GIP
Related Party Transaction
Consideration transferred			$ 3,125,000,000
Oil and Gas, Purchased | Devon
Related Party Transaction
Product sales																		$ 321,300,000
Oil and Gas, Purchased | EnLink Midstream Partners, LP | Devon
Related Party Transaction
Product sales																					$ 615,500,000
EOGP | ENLC
Related Party Transaction
Noncontrolling interest percentage		16.10%
ENLC
Related Party Transaction
Equity interest issued or issuable, number of shares (in shares)		55,827,221
Unsecured Debt | Term Loan Due 2029
Related Party Transaction
Stated interest rate																						5.375%
[1]	Includes related party cost of sales of $21.7 million , $114.1 million , and $211.0 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lease liability	$ 103
Right-of-use asset	80.4
Office Lease
Lessee, Lease, Description [Line Items]
Lease liability	60
Right-of-use asset	39.8
Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Lease liability	27.1
Right-of-use asset	27.1
Office Equipment
Lessee, Lease, Description [Line Items]
Lease liability	0.6
Right-of-use asset	0.6
Land
Lessee, Lease, Description [Line Items]
Lease liability	15.3
Right-of-use asset	$ 12.9
Minimum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Maximum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	3 years

Leases - Lease Balances Recorde

Leases - Lease Balances Recorded on the Consolidated Balance Sheet (Details) $ in Millions	Dec. 31, 2019USD ($)
Operating leases:
Other assets, net	$ 80.4
Other current liabilities	21.1
Other long-term liabilities	$ 81.9
Weighted-average remaining lease term—Operating leases	10 years 7 months 6 days
Weighted-average discount rate—Operating leases	5.10%

Leases - Components of Total Le

Leases - Components of Total Lease Expense (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Finance lease expense:
Amortization of right-of-use asset	$ 5.2
Interest on lease liability	0.1
Operating lease expense:
Long-term operating lease expense	28.7
Short-term lease expense	32
Variable lease expense	7.7
Total lease expense	$ 68.4

Leases - Other Information (Det

Leases - Other Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Cash payments for finance leases included in cash flows from financing activities	$ 1.2
Cash payments for operating leases included in cash flows from operating activities	29.8
Right-of-use assets obtained in exchange for operating lease liabilities	$ 104.1

Leases - Maturity of Lease Liab

Leases - Maturity of Lease Liability (Details) $ in Millions	Dec. 31, 2019USD ($)
Undiscounted operating lease liability
Total	$ 141.2
2020	25
2021	18.7
2022	11.7
2023	9.7
2024	9.1
Thereafter	67
Reduction due to present value
Total	(38.2)
2020	(4.7)
2021	(3.9)
2022	(3.4)
2023	(3.1)
2024	(2.7)
Thereafter	(20.4)
Operating lease liability
Total	103
2020	20.3
2021	14.8
2022	8.3
2023	6.6
2024	6.4
Thereafter	$ 46.6

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($)	1 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Apr. 09, 2019	Dec. 11, 2018	May 11, 2017	Jul. 14, 2016	May 12, 2015	Nov. 12, 2014	Mar. 19, 2014
Debt Instrument
Outstanding Principal	$ 4,350,000,000	$ 4,800,000,000
Premium (Discount)	(6,100,000)	(5,900,000)
Long-Term Debt	4,343,900,000	4,794,100,000
Less: debt issuance cost	(24,300,000)	(29,800,000)
Current maturities of long-term debt	(399,800,000)	0
Long-term debt, net of unamortized issuance cost	3,919,800,000	4,764,300,000
Amortization	15,300,000	10,900,000
Related party debt
Debt Instrument
Outstanding Principal	0	1,700,000,000
Premium (Discount)	0	0
Long-Term Debt	0	1,700,000,000
Term Loan due 2021
Debt Instrument
Outstanding Principal	850,000,000	0
Premium (Discount)	0	0
Long-Term Debt	850,000,000	0
2.70% Senior unsecured notes due 2019
Debt Instrument
Outstanding Principal	400,000,000	0
Premium (Discount)	0	0
Long-Term Debt	$ 400,000,000	$ 0
Debt instrument, face amount			$ 400,000,000						$ 400,000,000
Stated interest rate	2.70%	2.70%							2.70%
4.40% Senior unsecured notes due 2024
Debt Instrument
Outstanding Principal	$ 550,000,000	$ 550,000,000
Premium (Discount)	1,800,000	1,500,000
Long-Term Debt	551,800,000	$ 551,500,000
Debt instrument, face amount								$ 100,000,000	$ 450,000,000
Stated interest rate		4.40%							4.40%
4.15% Senior unsecured notes due 2025
Debt Instrument
Outstanding Principal	750,000,000	$ 750,000,000
Premium (Discount)	(900,000)	(700,000)
Long-Term Debt	749,100,000	$ 749,300,000
Debt instrument, face amount							$ 750,000,000
Stated interest rate		4.15%					4.15%
4.85% Senior unsecured notes due 2026
Debt Instrument
Outstanding Principal	500,000,000	$ 500,000,000
Premium (Discount)	(500,000)	(500,000)
Long-Term Debt	499,500,000	$ 499,500,000
Debt instrument, face amount						$ 500,000,000
Stated interest rate		4.85%				4.85%
5.60% Senior unsecured notes due 2044
Debt Instrument
Outstanding Principal	350,000,000	$ 350,000,000
Premium (Discount)	(200,000)	(200,000)
Long-Term Debt	349,800,000	$ 349,800,000
Debt instrument, face amount									$ 350,000,000
Stated interest rate		5.60%							5.60%
5.05% Senior unsecured notes due 2045
Debt Instrument
Outstanding Principal	450,000,000	$ 450,000,000
Premium (Discount)	(6,200,000)	(5,900,000)
Long-Term Debt	443,800,000	$ 444,100,000
Debt instrument, face amount							$ 150,000,000	$ 300,000,000
Stated interest rate		5.05%						5.05%
5.45% Senior unsecured notes due 2047
Debt Instrument
Outstanding Principal	500,000,000	$ 500,000,000
Premium (Discount)	(100,000)	(100,000)
Long-Term Debt	$ 499,900,000	$ 499,900,000
Debt instrument, face amount					$ 500,000,000
Stated interest rate		5.45%			5.45%
Unsecured Debt | Term Loan due 2021
Debt Instrument
Debt instrument, face amount		$ 850,000,000		$ 850,000,000
Debt instrument, term	3 years
Effective interest rate		3.90%

Long-Term Debt - Summary of Mat

Long-Term Debt - Summary of Maturities for Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
2020	$ 0
2021	850
2022	0
2023	0
2024	900
Thereafter	3,050
Subtotal	4,800	$ 4,350
Less: net discount	(5.9)	(6.1)
Less: debt issuance cost	(29.8)	(24.3)
Long-term debt, net of unamortized issuance cost	$ 4,764.3	$ 3,919.8

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Apr. 09, 2019USD ($)	Dec. 11, 2018USD ($)	Jun. 01, 2017USD ($)	May 11, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jul. 14, 2016USD ($)	May 12, 2015USD ($)	Nov. 12, 2014USD ($)	Sep. 20, 2014USD ($)	Jul. 20, 2014USD ($)	Mar. 19, 2014USD ($)	Mar. 07, 2014USD ($)
Debt Instrument
Long-term debt					$ 4,794,100,000	$ 4,343,900,000
Premium (Discount)					(5,900,000)	(6,100,000)
Repurchased face amount			$ 162,500,000
Repurchase amount			$ 174,100,000
Gain on extinguishment of debt					0	0	$ 9,000,000
Proceeds from issuance of long-term debt	$ 496,500,000				$ 4,160,000,000	$ 3,904,000,000	$ 2,315,900,000
Redemption price, percentage			103.60%		100.00%
Minimum
Debt Instrument
Stated interest rate					4.15%	2.70%
Maximum
Debt Instrument
Stated interest rate					5.60%	5.60%
Related party debt
Debt Instrument
Long-term debt					$ 1,700,000,000	$ 0
Outstanding letters of credit					0	9,800,000
Additional borrowing limit		$ 1,750,000,000			2,250,000,000
Premium (Discount)					0	0
Fair value of amount outstanding					350,000,000
Term Loan due 2021
Debt Instrument
Long-term debt					0	850,000,000
Ratio of consolidated indebtedness to consolidated EBITDA		5
Premium (Discount)					0	0
Term Loan due 2021 | Maximum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA		5.5
Conditional acquisition purchase price		$ 50,000,000
Unsecured Debt
Debt Instrument
Debt instrument, face amount									$ 900,000,000				$ 1,200,000,000
7.125% Senior unsecured notes due 2022
Debt Instrument
Debt instrument, face amount														$ 196,500,000
Stated interest rate														7.125%
Long-term debt														$ 226,000,000
Premium (Discount)														$ (29,500,000)
Repurchased face amount											$ 15,500,000	$ 18,500,000
Repurchase amount											$ 17,000,000	$ 20,000,000
2.70% Senior unsecured notes due 2019
Debt Instrument
Long-term debt					$ 0	$ 400,000,000
Debt instrument, face amount	400,000,000												$ 400,000,000
Stated interest rate					2.70%	2.70%							2.70%
Premium (Discount)					$ 0	$ 0
Selling price of debt instrument													99.85%
4.40% Senior unsecured notes due 2024
Debt Instrument
Long-term debt					$ 551,500,000	551,800,000
Debt instrument, face amount										$ 100,000,000			$ 450,000,000
Stated interest rate					4.40%								4.40%
Premium (Discount)					$ 1,500,000	1,800,000
Selling price of debt instrument									96.381%	104.007%			99.83%
5.60% Senior unsecured notes due 2044
Debt Instrument
Long-term debt					$ 349,800,000	349,800,000
Debt instrument, face amount													$ 350,000,000
Stated interest rate					5.60%								5.60%
Premium (Discount)					$ (200,000)	(200,000)
Selling price of debt instrument													99.925%
5.05% Senior unsecured notes due 2045
Debt Instrument
Long-term debt					$ 444,100,000	443,800,000
Debt instrument, face amount									$ 150,000,000	$ 300,000,000
Stated interest rate					5.05%					5.05%
Premium (Discount)					$ (5,900,000)	(6,200,000)
Selling price of debt instrument										99.452%
4.15% Senior unsecured notes due 2025
Debt Instrument
Long-term debt					$ 749,300,000	749,100,000
Debt instrument, face amount									$ 750,000,000
Stated interest rate					4.15%				4.15%
Premium (Discount)					$ (700,000)	(900,000)
Selling price of debt instrument									99.827%
4.85% Senior unsecured notes due 2026
Debt Instrument
Long-term debt					$ 499,500,000	499,500,000
Debt instrument, face amount								$ 500,000,000
Stated interest rate					4.85%			4.85%
Premium (Discount)					$ (500,000)	(500,000)
Selling price of debt instrument								99.859%
5.45% Senior unsecured notes due 2047
Debt Instrument
Long-term debt					$ 499,900,000	499,900,000
Debt instrument, face amount				$ 500,000,000
Stated interest rate				5.45%	5.45%
Premium (Discount)					$ (100,000)	$ (100,000)
Selling price of debt instrument				99.981%
Proceeds from issuance of long-term debt				$ 495,200,000
Unsecured Debt | Related party debt
Debt Instrument
Ratio of consolidated EBITDA to consolidated interest charges		2.5
Ratio of consolidated indebtedness to consolidated EBITDA		5
Ratio of consolidated indebtedness to consolidated EBITDA during an acquisition period		5.5
Unsecured Debt | Related party debt | Federal Funds
Debt Instrument
Variable interest rate		0.50%
Unsecured Debt | Related party debt | Eurodollar
Debt Instrument
Variable interest rate					1.00%
Unsecured Debt | Related party debt | Minimum
Debt Instrument
Conditional acquisition purchase price		$ 50,000,000
Unsecured Debt | Related party debt | Minimum | LIBOR
Debt Instrument
Variable interest rate		1.125%
Unsecured Debt | Related party debt | Minimum | Eurodollar
Debt Instrument
Variable interest rate		0.125%
Unsecured Debt | Related party debt | Maximum | LIBOR
Debt Instrument
Variable interest rate		2.00%
Unsecured Debt | Related party debt | Maximum | Eurodollar
Debt Instrument
Variable interest rate		1.00%
Unsecured Debt | Term Loan Due 2029
Debt Instrument
Debt instrument, face amount	$ 500,000,000
Stated interest rate	5.375%
Percentage price of debt issued	100.00%
Unsecured Debt | Term Loan due 2021
Debt Instrument
Debt instrument, face amount		$ 850,000,000			$ 850,000,000
Letter of Credit | Related party debt
Debt Instrument
Maximum borrowing capacity		$ 500,000,000
Covenant, percentage of letter of credits guaranteed					105.00%
Line of Credit | Term Loan due 2021
Debt Instrument
Ratio of consolidated EBITDA to consolidated interest charges		2.5
Line of Credit | Term Loan due 2021 | Federal Funds
Debt Instrument
Variable interest rate		0.50%
Line of Credit | Term Loan due 2021 | Eurodollar
Debt Instrument
Variable interest rate		1.00%
Line of Credit | Term Loan due 2021 | Minimum | LIBOR
Debt Instrument
Variable interest rate		1.00%
Line of Credit | Term Loan due 2021 | Minimum | Eurodollar
Debt Instrument
Variable interest rate		0.00%
Line of Credit | Term Loan due 2021 | Maximum | LIBOR
Debt Instrument
Variable interest rate		1.75%
Line of Credit | Term Loan due 2021 | Maximum | Eurodollar
Debt Instrument
Variable interest rate		0.75%
ENLC
Debt Instrument
Stated interest rate					5.375%
ENLC | Related party debt
Debt Instrument
Fair value of amount outstanding					$ 350,000,000
Letter of Credit | ENLC | Related party debt
Debt Instrument
Fair value of amount outstanding					$ 4,800,000

Long-Term Debt - Summary of Red

Long-Term Debt - Summary of Redemption Provision Terms (Details)	12 Months Ended
	Dec. 31, 2019
2.70% Senior unsecured notes due 2019
Debt Instrument
Redemption premium, percentage	0.20%
4.40% Senior unsecured notes due 2024
Debt Instrument
Redemption premium, percentage	0.25%
4.15% Senior unsecured notes due 2025
Debt Instrument
Redemption premium, percentage	0.30%
4.85% Senior unsecured notes due 2026
Debt Instrument
Redemption premium, percentage	0.50%
5.375% Senior unsecured notes due 2029
Debt Instrument
Redemption premium, percentage	50.00%
5.60% Senior unsecured notes due 2044
Debt Instrument
Redemption premium, percentage	0.30%
5.05% Senior unsecured notes due 2045
Debt Instrument
Redemption premium, percentage	0.30%
5.45% Senior unsecured notes due 2047
Debt Instrument
Redemption premium, percentage	0.40%

Income Taxes - Summary of Tax E

Income Taxes - Summary of Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.4)	$ (1.8)	$ (2.6)
Deferred tax benefit (expense)	(2.1)	3.9	26.6
Total income tax benefit (expense)	$ (2.5)	$ 2.1	$ 24

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	Dec. 22, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Income tax benefit	$ 24,900,000
Deferred tax liability		$ 44,500,000	$ 42,400,000
Unrecognized tax benefits		0	0	$ 0
Clearfield Energy
Business Acquisition [Line Items]
Deferred tax liability		$ 39,100,000	$ 38,700,000

Partners' Capital - Narrative a

Partners' Capital - Narrative and Distribution Activity (Details) $ / shares in Units, $ in Millions	Jan. 25, 2019	Sep. 30, 2017USD ($)$ / sharesshares	Jan. 31, 2016$ / sharesshares	Dec. 31, 2014USD ($)	Dec. 31, 2019USD ($)$ / sharesshares	Sep. 30, 2019USD ($)shares	Jun. 30, 2019USD ($)shares	Mar. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2018USD ($)$ / sharesshares	Mar. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)shares	Sep. 30, 2017USD ($)$ / sharesshares	Jun. 30, 2017USD ($)$ / sharesshares	Mar. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Jun. 30, 2017
Partners' capital
Proceeds from sale of common units																	$ 0	$ 46.1	$ 106.9
Partners capital, common units conversion ratio	1.15
Percentage of available cash to distribute					100.00%												100.00%
Period after quarter for distribution																	45 days
Distribution to common unitholders and to general partner																	$ 682.6	613.5	604.8
General Partner Interest | Incentive Distribution Level 1
Partners' capital
Incentive distribution for general partner																	13.00%
Incentive distribution, conditional distribution per unit (in dollars per share) | $ / shares																	$ 0.25
General Partner Interest | Incentive Distribution Level 2
Partners' capital
Incentive distribution for general partner																	23.00%
Incentive distribution, conditional distribution per unit (in dollars per share) | $ / shares																	$ 0.3125
General Partner Interest | Incentive Distribution Level 3
Partners' capital
Incentive distribution for general partner																	48.00%
Incentive distribution, conditional distribution per unit (in dollars per share) | $ / shares																	$ 0.375
Series B Preferred Unitholders
Partners' capital
Partners capital, common units conversion ratio			1
Distributions to preferred unitholders																	$ 67.4	65	15.9
Series C Preferred Unitholders
Partners' capital
Proceeds from issuance of Series C Preferred Units																	0	0	394
Distributions to preferred unitholders																	$ 24	24	$ 5.6
Limited Partner | 2017 EDA
Partners' capital
Commissions																		$ 0.5
Limited Partner | Common Units
Partners' capital
Partners' capital account, units, sold in public offering (in shares) | shares																	55,800,000	2,600,000	6,200,000
Distribution/unit (in dollars per share) | $ / shares					$ 0.390				$ 0.390	$ 0.390	$ 0.390	$ 0.390		$ 0.390	$ 0.390	$ 0.390
Limited Partner | Common Units | 2017 EDA
Partners' capital
Partners' capital account, units, sold in public offering (in shares) | shares																		2,600,000	6,200,000
Proceeds from sale of common units																		$ 46.1	$ 106.9
Commissions																			1.1
Registration fees																			$ 0.2
Limited Partner | Series B Preferred Unitholders
Partners' capital
Partners' capital account, units, sold in private placement (in shares) | shares			50,000,000
Price per share (in dollars per share) | $ / shares			$ 15
Conversion obligation period of consecutive trading days																	30 days
Average trading price, number of trading days																	2 days
Percent of issue price																	150.00%
Annual rate on issue price payable in kind																				8.50%
Annual rate on issue price payable in cash														28.125%
Annual rate on issue price														0.25%			0.25%
Preferred units, distributions (in shares) | shares					148,999	148,627	148,257	147,887	425,785	422,720	419,678	416,657	413,658	410,681	1,178,672	1,154,147
Proceeds from issuance of Series C Preferred Units					$ 16.8	$ 17.1	$ 17.1	$ 16.7	$ 16.5	$ 16.4	$ 16.3	$ 16.2	$ 16.1	$ 15.9	$ 0	$ 0
Limited Partner | Series C Preferred Unitholders
Partners' capital
Partners' capital account, units, sold in public offering (in shares) | shares		400,000
Partners' capital account, units, sold in private placement (in shares) | shares																			400,000
Proceeds from issuance of Series C Preferred Units		$ 394
Partners capital account, redemption price (in dollars per share) | $ / shares		$ 1,000
Partners' capital account, redemption period following review or appeal		120 days
Partners' capital account, redemption price when purchased in whole (in dollars per share) | $ / shares		$ 1,020
Partners' capital account, dividend rate, percentage		6.00%
LIBOR | Limited Partner | Series C Preferred Unitholders
Partners' capital
Partners' capital account, distributions, variable floating rate percentage		4.11%
EnLink Midstream Partners, LP
Partners' capital
Distribution to common unitholders and to general partner																	$ 527.6
EnLink Midstream Partners, LP | Limited Partner | Common Units | 2017 EDA
Partners' capital
Agreement for gross sales of common units (up to)				$ 350

Partners' Capital - Net Income

Partners' Capital - Net Income Allocated to the General Partner (Details) - General Partner Interest - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Incentive
Income allocation for incentive distributions	$ 0	$ 59.5	$ 58.9
Unit-based compensation attributable to ENLC’s restricted and performance units	(37)	(20.3)	(21)
General partner share of net income (loss)	(1.4)	(0.6)	0.4
General partner interest in EOGP acquisition	2.4	27.5	4.8
General partner interest in net income (loss)	$ (36)	$ 66.1	$ 43.1

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments
Contributions		$ 0	$ 0.1	$ 12.6
Distributions		20.2	22.7	13.5
Equity in income (loss)		(16.8)	13.3	9.6
Net proceeds received		0	0	189.7
Total investment in unconsolidated affiliates		43.1	$ 80.1
Impairment charge on property, plant, and equipment		$ 7.9		$ 17.1
Gulf Coast Fractionators
Schedule of Equity Method Investments
Ownership interest		38.75%	38.75%	38.75%
Distributions		$ 19.2	$ 22.3	$ 12.7
Equity in income (loss)		16.5	15.8	$ 12.6
Total investment in unconsolidated affiliates		$ 39.2	$ 41.9
Cedar Cove JV
Schedule of Equity Method Investments
Ownership interest		30.00%	30.00%	30.00%
Contributions		$ 0	$ 0.1	$ 12.6
Distributions		1	0.4	0.8
Equity in income (loss)		(33.3)	(2.5)	$ 0.4
Total investment in unconsolidated affiliates		3.9	38.2
Howard Energy Partners
Schedule of Equity Method Investments
Ownership interest				31.00%
Equity in income (loss)		0	$ 0	$ (3.4)
Loss on the sale of disposal of HEP Interests				$ 3.4
Net proceeds received	$ 189.7
Cedar Cove JV
Schedule of Equity Method Investments
Impairment charge on property, plant, and equipment		$ 31.4

Employee Incentive Plans - Long

Employee Incentive Plans - Long Term Incentive Plans (Details) $ in Millions	Jan. 25, 2019	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Compensation allocation
Partners capital, common units conversion ratio	1.15
Total unit-based compensation expense		$ 39.2	$ 40.8	$ 47.8
Cost of unit-based compensation charged to general and administrative expense
Compensation allocation
Total unit-based compensation expense		32.5	30	37.1
Cost of unit-based compensation charged to operating expense
Compensation allocation
Total unit-based compensation expense		$ 6.7	$ 10.8	$ 10.7

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) $ / shares in Units, $ in Millions	Jan. 25, 2019	Jul. 23, 2018	Oct. 31, 2019$ / shares	Jun. 30, 2019$ / shares	Mar. 31, 2019USD ($)$ / sharesshares	Mar. 31, 2018$ / shares	Mar. 31, 2017$ / shares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)shares
Weighted Average Grant-Date Fair Value
Granted (in dollars per share) | $ / shares						$ 19.24	$ 25.73
Partners capital, common units conversion ratio	1.15
Grant date fair value assumptions
TSR price (in dollars per share) | $ / shares						$ 15.44	$ 17.55
Risk-free interest rate						2.38%	1.62%
Volatility factor						43.85%	43.94%
Distribution yield						10.50%	8.70%
Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (in shares)								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	2,556,270
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share) | $ / shares								$ 14.43
Vested (in dollars per share) | $ / shares								10.02
Forfeited (in dollars per share) | $ / shares								11.93
Converted to ENLC (in dollars per share) | $ / shares								16.11
Non-vested, end of period (in dollars per share) | $ / shares								$ 0	$ 14.43
Units withheld for payroll taxes (in shares)								249,201
Aggregate intrinsic value of units vested | $								$ 8	$ 13.1	$ 16.6
Fair value of units vested | $								$ 7.2	$ 16.4	22.6
Vesting period								3 years
Restricted Stock Units (RSUs) | ENLC
Number of Units
Non-vested, beginning of period (in shares)								2,425,867
Granted (in shares)								2,027,653
Vested (in shares)					(420,842)			(1,886,905)
Forfeited (in shares)								(606,276)
Converted to ENLC (in shares)								2,103,266
Non-vested, end of period (in shares)								4,063,605	2,425,867
Aggregate intrinsic value, end of period | $								$ 24.9
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share) | $ / shares								$ 14.62
Granted (in dollars per share) | $ / shares								11.09
Vested (in dollars per share) | $ / shares								12.06
Forfeited (in dollars per share) | $ / shares								13.85
Converted to ENLC (in dollars per share) | $ / shares								14.01
Non-vested, end of period (in dollars per share) | $ / shares								$ 13.85	$ 14.62
Units withheld for payroll taxes (in shares)								626,133
Aggregate intrinsic value of units vested | $								$ 17.3	$ 12.8	15.3
Fair value of units vested | $					$ 4.8			22.8	$ 16.5	$ 22.2
Unrecognized compensation cost related to non-vested restricted incentive units | $								$ 23.1
Unrecognized compensation costs, weighted average period for recognition								1 year 7 months 6 days
Performance Units
Number of Units
Non-vested, beginning of period (in shares)								451,669
Vested (in shares)								(161,410)		0
Converted to ENLC (in shares)								(290,259)
Non-vested, end of period (in shares)								0	451,669
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share) | $ / shares								$ 17.74
Vested (in dollars per share) | $ / shares								10.54
Converted to ENLC (in dollars per share) | $ / shares								28.31
Non-vested, end of period (in dollars per share) | $ / shares								$ 0	$ 17.74
Units withheld for payroll taxes (in shares)								62,403
Aggregate intrinsic value of units vested | $								$ 2.1	$ 5
Fair value of units vested | $								$ 1.7	$ 7.7
Vesting period								3 years
Performance Units | ENLC
Number of Units
Non-vested, beginning of period (in shares)								418,149
Granted (in shares)								1,202,105
Vested (in shares)								(374,745)		0
Forfeited (in shares)								(261,451)
Converted to ENLC (in shares)								333,798
Non-vested, end of period (in shares)								1,317,856	418,149
Aggregate intrinsic value, end of period | $								$ 8.1
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share) | $ / shares								$ 19.15
Granted (in dollars per share) | $ / shares			$ 7.29	$ 9.92	$ 13.10	$ 21.63	$ 28.77	11.73
Vested (in dollars per share) | $ / shares								21.08
Forfeited (in dollars per share) | $ / shares								15.68
Converted to ENLC (in dollars per share) | $ / shares								25.84
Non-vested, end of period (in dollars per share) | $ / shares								$ 14.22	$ 19.15
Units withheld for payroll taxes (in shares)								146,218
Aggregate intrinsic value of units vested | $								$ 3.4	$ 4.7
Fair value of units vested | $								$ 7.9	$ 7.7
Vesting period								3 years
Unrecognized compensation cost related to non-vested restricted incentive units | $								$ 10.2
Unrecognized compensation costs, weighted average period for recognition								1 year 9 months 18 days
Grant date fair value assumptions
TSR price (in dollars per share) | $ / shares			$ 7.42	$ 9.84	$ 10.92	$ 16.55	$ 18.29
Risk-free interest rate			1.44%	1.72%	2.42%	2.38%	1.62%
Volatility factor			35.00%	33.50%	33.86%	51.36%	52.07%
Distribution yield			10.10%	11.50%	9.70%	6.70%	5.40%
Performance Units | EnLink Midstream Partners, LP
Weighted Average Grant-Date Fair Value
Additional compensation expense not yet recognized | $								$ 0.7
Performance Units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting		0.00%						0.00%
Performance Units | Minimum | ENLC
Weighted Average Grant-Date Fair Value
Percent of units vesting								0.00%
Performance Units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting		100.00%						200.00%
Performance Units | Maximum | ENLC
Weighted Average Grant-Date Fair Value
Percent of units vesting								200.00%
ENLC Performance Shares
Weighted Average Grant-Date Fair Value
Additional compensation expense not yet recognized | $								$ 2.1
Below Threshold | TSR Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								0.00%
Below Threshold | Cash Flow Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								0.00%
Threshold | TSR Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								50.00%
Threshold | Cash Flow Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								50.00%
Target | TSR Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								100.00%
Target | Cash Flow Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								100.00%
Maximum | TSR Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								200.00%
Maximum | Cash Flow Performance Unit
Weighted Average Grant-Date Fair Value
Performance vesting percentage								200.00%

Employee Incentive Plans - Bene

Employee Incentive Plans - Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement [Abstract]
Employer matching contribution, percent	100.00%
Employer matching contribution, percent of employees' gross pay	6.00%
Non-discretionary contribution percentage	2.00%
Employer benefit plan contributions	$ 9.4	$ 8.3	$ 7.6

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 30, 2019	May 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative, notional amount				$ 850,000,000
Derivative, fixed interest rate				2.27825%
Settlement gain (loss)	$ (14,500,000)	$ (2,100,000)			$ (2,200,000)
Loss on designated cash flow hedge	(12,400,000)	0	$ (2,100,000)
Gain (loss) reclassified to earnings	(400,000)	0	$ 0
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	5,700,000
Derivative
Fair value of derivative liabilities—current	(14,400,000)	(21,800,000)
Fair value of derivative liabilities—long-term	(6,800,000)	$ (2,400,000)
Interest Rate Swap
Derivative
Fair value of derivative liabilities—current	(5,600,000)
Fair value of derivative liabilities—long-term	(6,800,000)
Net fair value of derivatives	$ (12,400,000)

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments
Gain (loss) on derivative activity	$ 14.4	$ 5.2	$ (4.2)
Commodity Swaps
Derivative Instruments
Change in fair value of derivatives	(0.1)	10.1	4.7
Realized gain (loss) on derivatives	14.5	(4.9)	(8.9)
Gain (loss) on derivative activity	$ 14.4	$ 5.2	$ (4.2)

Derivatives - Assets and Liabil

Derivatives - Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative
Fair value of derivative assets—current	$ 12.9	$ 28.6
Fair value of derivative assets—long-term	4.3	4.1
Fair value of derivative liabilities—current	(14.4)	(21.8)
Fair value of derivative liabilities—long-term	(6.8)	(2.4)
Commodity Swap
Derivative
Fair value of derivative assets—current	12.9	28.6
Fair value of derivative assets—long-term	4.3	4.1
Fair value of derivative liabilities—current	(8.8)	(21.8)
Fair value of derivative liabilities—long-term	0	(2.4)
Net fair value of derivatives	$ 8.4	$ 8.5

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) - Commodity gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MMBTUMMBblsgal
Derivative
Net Fair Value	$ 8.4
Maximum loss if counterparties fail to perform	17.2
Possible reduction in maximum loss if counterparties fail to perform	$ 8.4
NGL | Short
Derivative
Notional amount (in gallons or mmbbls) | gal	64
Net Fair Value	$ 1.7
NGL | Long
Derivative
Notional amount (in gallons or mmbbls) | gal	11.7
Net Fair Value	$ (0.5)
Natural gas | Short
Derivative
Notional amount (in mmbtu) | MMBTU	4.7
Net Fair Value	$ 1
Natural gas | Long
Derivative
Notional amount (in mmbtu) | MMBTU	3.7
Net Fair Value	$ (0.4)
Crude and condensate | Short
Derivative
Notional amount (in gallons or mmbbls) | MMBbls	12.8
Net Fair Value	$ (1)
Crude and condensate | Long
Derivative
Notional amount (in gallons or mmbbls) | MMBbls	2
Net Fair Value	$ 7.6

Fair Value Measurements - Measu

Fair Value Measurements - Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Interest Rate Swap
Measured at fair value
Net Fair Value	$ (12.4)
Commodity Swaps
Measured at fair value
Net Fair Value	8.4	$ 8.5
Level 2 | Interest Rate Swap | Recurring
Measured at fair value
Net Fair Value	(12.4)	0
Level 2 | Commodity Swaps | Recurring
Measured at fair value
Net Fair Value	$ 8.4	$ 8.5

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Dec. 31, 2019	May 31, 2019	Dec. 31, 2018
Fair Value
Debt issuance costs	$ 29,800,000		$ 24,300,000
Senior unsecured notes	$ 3,100,000,000		$ 3,500,000,000
Minimum
Fair Value
Stated interest rate	4.15%		2.70%
Maximum
Fair Value
Stated interest rate	5.60%		5.60%
Carrying Value
Fair Value
Long-term debt	$ 4,764,300,000		$ 4,319,600,000
Obligations under financing lease	0		2,500,000
Secured term loan receivable	0		51,100,000
Fair Value
Fair Value
Long-term debt	4,444,200,000		3,953,600,000
Obligations under financing lease	0		2,200,000
Secured term loan receivable	0		$ 51,100,000
Second Lien Secured Term Loan
Fair Value
Maximum borrowing capacity		$ 58,000,000
ENLC
Fair Value
Senior unsecured notes	$ 500,000,000
Stated interest rate	5.375%

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2014	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Litigation settlement amount awarded from other party	$ 6.1	$ 26

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting
Revenue from contracts with customers														$ 6,038.5	$ 7,693.8
Cost of sales	[1]													(4,392.5)	(6,008)	$ (4,361.5)
Operating expenses														(467.1)	(453.4)	(418.7)
Gain (loss) on derivative activity														14.4	5.2	(4.2)
Segment profit														1,193.3	1,237.6	959.4
Depreciation and amortization														(617)	(577.3)	(545.3)
Impairments		$ (198.2)	$ 0	$ 0	$ 0	$ (341.2)	$ (24.6)	$ 0	$ 0	$ (8.3)	$ (1.8)	$ 0	$ (7)	(198.2)	(365.8)	(17.1)
Goodwill		0				190.3				422.3				0	190.3	422.3
Capital expenditures														748.4	849.9	768.1
Total identifiable assets		9,134.6				9,571.3								9,134.6	9,571.3
Corporate
Segment Reporting
Revenue from contracts with customers														(908.8)	(1,108.8)
Cost of sales														908.8	1,108.8	855.4
Operating expenses														0	0	0
Gain (loss) on derivative activity														14.4	5.2	(4.2)
Segment profit														14.4	5.2	(4.2)
Depreciation and amortization														(8.4)	(8.7)	(10.4)
Impairments														0	0	0
Goodwill		0				0				0				0	0	0
Capital expenditures														6.9	5.3	26.4
Total identifiable assets		120.7				222.3								120.7	222.3
Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,542.3	3,030.3
Cost of sales														(2,283.9)	(2,808.3)	(1,628.5)
Operating expenses														(112.9)	(96.1)	(85.1)
Gain (loss) on derivative activity														0	0	0
Segment profit														145.5	125.9	83.6
Depreciation and amortization														(119.8)	(111)	(109.9)
Impairments														(3.5)	(138.5)	0
Goodwill		0				0				29.3				0	0	29.3
Capital expenditures														364.5	271.7	186.1
Total identifiable assets		2,281.1				2,096.8								2,281.1	2,096.8
North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														601.1	684.1
Cost of sales														(208.8)	(199.2)	(264.5)
Operating expenses														(102.9)	(112.7)	(121.8)
Gain (loss) on derivative activity														0	0	0
Segment profit														289.4	372.2	358.7
Depreciation and amortization														(139.8)	(127.9)	(127)
Impairments														(2.1)	(202.7)	0
Goodwill		0				0				202.7				0	0	202.7
Capital expenditures														39	24.7	18.2
Total identifiable assets		1,135.8				1,308.2								1,135.8	1,308.2
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														1,181.1	1,299.8
Cost of sales														(627)	(743.6)	(523)
Operating expenses														(104)	(90.3)	(64.6)
Gain (loss) on derivative activity														0	0	0
Segment profit														450.1	465.9	287.2
Depreciation and amortization														(194.9)	(178.8)	(156.3)
Impairments														(190.5)	0	0
Goodwill		0				190.3				190.3				0	190.3	190.3
Capital expenditures														238.1	493.8	450.1
Total identifiable assets		3,035				3,209.5								3,035	3,209.5
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,622.8	3,788.4
Cost of sales														(2,181.6)	(3,365.7)	(2,800.9)
Operating expenses														(147.3)	(154.3)	(147.2)
Gain (loss) on derivative activity														0	0	0
Segment profit														293.9	268.4	234.1
Depreciation and amortization														(154.1)	(150.9)	(141.7)
Impairments														(2.1)	(24.6)	(17.1)
Goodwill		0				0				$ 0				0	0	0
Capital expenditures														99.9	54.4	87.3
Total identifiable assets		$ 2,562				$ 2,734.5								2,562	2,734.5
Product sales
Segment Reporting
Revenue from contracts with customers														5,030.1	6,512.3	4,358.4
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers														0	0	0
Product sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,070.2	2,496.9	1,344
Product sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														160.2	170.1	162.5
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														365.6	300.8	128.8
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,434.1	3,544.5	2,723.1
Natural gas sales
Segment Reporting
Revenue from contracts with customers														876.6	1,013.7
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Natural gas sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														94.3	152.3
Natural gas sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														129.3	140.6
Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														236.4	189.7
Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														416.6	531.1
NGL sales
Segment Reporting
Revenue from contracts with customers														1,777	2,841
NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
NGL sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.9	0.5
NGL sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														30.9	29
NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														19.6	25.2
NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														1,725.6	2,786.3
Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers														2,376.5	2,657.6
Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Crude oil and condensate sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														1,975	2,344.1
Crude oil and condensate sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0.5
Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														109.6	85.9
Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														291.9	227.1
Product sales—related parties
Segment Reporting
Revenue from contracts with customers														0	41	144.9
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(910.4)	(1,105.5)	(721.8)
Product sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														361.6	453.8	357
Product sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														100.3	51.2	120.5
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														421.1	593.6	349.4
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														27.4	47.9	39.8
Natural gas sales—related parties
Segment Reporting
Revenue from contracts with customers														0	2.5
Natural gas sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(0.4)	0
Natural gas sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.4	(0.3)
Natural gas sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0
Natural gas sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	2.5
Natural gas sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0.3
NGL sales—related parties
Segment Reporting
Revenue from contracts with customers														0	37.4
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(889.3)	(1,104.3)
NGL sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														347.7	454.1
NGL sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														94.8	49.4
NGL sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														421.1	590.8
NGL sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														25.7	47.4
Crude oil and condensate sales—related parties
Segment Reporting
Revenue from contracts with customers														0	1.1
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(20.7)	(1.2)
Crude oil and condensate sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														13.5	0
Crude oil and condensate sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														5.5	1.8
Crude oil and condensate sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0.3
Crude oil and condensate sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														1.7	0.2
Midstream services
Segment Reporting
Revenue from contracts with customers														1,008.4	763.3	552.3
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers														0	0	0
Midstream services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														110.5	64.7	77.5
Midstream services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														340.6	231.1	51.6
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														392.6	274.8	155
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														164.7	192.7	268.2
Gathering and transportation
Segment Reporting
Revenue from contracts with customers														538	386.3
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Gathering and transportation | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														48.8	28
Gathering and transportation | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														196.4	146.3
Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														234.5	143.2
Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														58.3	68.8
Processing
Segment Reporting
Revenue from contracts with customers														314.9	239.7
Processing | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Processing | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														30.5	23.8
Processing | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														143	83.9
Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														138.2	128.7
Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.2	3.3
NGL services
Segment Reporting
Revenue from contracts with customers														50.7	59.6
NGL services | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
NGL services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0
NGL services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.1	0
NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0
NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														50.6	59.6
Crude services
Segment Reporting
Revenue from contracts with customers														90.9	67.1
Crude services | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Crude services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														19.2	4.2
Crude services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0
Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														19.8	2.8
Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														51.9	60.1
Other services
Segment Reporting
Revenue from contracts with customers														13.9	10.6
Other services | Corporate
Segment Reporting
Revenue from contracts with customers														0	0
Other services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														12	8.7
Other services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														1.1	0.9
Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.1	0.1
Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.7	0.9
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers														0	377.2	688.2
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														1.6	(3.3)	(133.6)
Midstream services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	14.9	18.7
Midstream services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	231.7	410.4
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														1.8	130.6	241.6
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														(3.4)	3.3	$ 151.1
Gathering and transportation—related parties
Segment Reporting
Revenue from contracts with customers															203.3
Gathering and transportation—related parties | Corporate
Segment Reporting
Revenue from contracts with customers															0
Gathering and transportation—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers															0
Gathering and transportation—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers															122.7
Gathering and transportation—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers															80.6
Gathering and transportation—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers															0
Processing—related parties
Segment Reporting
Revenue from contracts with customers															157
Processing—related parties | Corporate
Segment Reporting
Revenue from contracts with customers															0
Processing—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers															0
Processing—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers															108.5
Processing—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers															48.5
Processing—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers															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														3.4	(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														(3.4)	3.3
Crude services—related parties
Segment Reporting
Revenue from contracts with customers														0	16.4
Crude services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(1.8)	0
Crude services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	14.9
Crude services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0	0
Crude services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														1.8	1.5
Crude services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														$ 0	0
Other services—related parties
Segment Reporting
Revenue from contracts with customers															0.5
Other services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers															0
Other services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers															0
Other services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers															0.5
Other services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers															0
Other services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers															$ 0
[1]	Includes related party cost of sales of $21.7 million , $114.1 million , and $211.0 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting [Abstract]
Segment profit													$ 1,193.3	$ 1,237.6	$ 959.4
General and administrative expenses													(139.2)	(130.2)	(123.5)
Gain (loss) on disposition of assets													1.9	(0.4)	0
Depreciation and amortization													(617)	(577.3)	(545.3)
Impairments	$ (198.2)	$ 0	$ 0	$ 0	$ (341.2)	$ (24.6)	$ 0	$ 0	$ (8.3)	$ (1.8)	$ 0	$ (7)	(198.2)	(365.8)	(17.1)
Loss on secured term loan receivable													(52.9)	0	0
Gain on litigation settlement													0	0	26
Operating income	$ (72.8)	$ 96.7	$ 53.4	$ 110.6	$ (185.3)	$ 92.5	$ 150.1	$ 106.6	$ 98.1	$ 73.4	$ 70.4	$ 57.6	$ 187.9	$ 163.9	$ 299.5

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 1,155.7	$ 1,408	$ 1,710	$ 1,779.2	$ 2,058.3	$ 2,114.3	$ 1,764.7	$ 1,761.7	$ 1,756.2	$ 1,397.9	$ 1,263.6	$ 1,321.9	$ 6,052.9	$ 7,699	$ 5,739.6
Impairments	198.2	0	0	0	341.2	24.6	0	0	8.3	1.8	0	7	198.2	365.8	17.1
Operating income (loss)	(72.8)	96.7	53.4	110.6	(185.3)	92.5	150.1	106.6	98.1	73.4	70.4	57.6	187.9	163.9	299.5
Net income (loss) attributable to ENLK	$ (163.6)	$ 42.4	$ 4.1	$ 62.8	$ (225.1)	$ 48.8	$ 111.5	$ 64.3	$ 78.8	$ 27.8	$ 30.4	$ 16.7	$ (54.3)	$ (0.5)	$ 153.7

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental disclosures of cash flow information:
Cash paid for interest	$ 218.5	$ 182.6	$ 163.8
Cash paid for income taxes	3.9	1.5	4.8
Non-cash investing activities:
Non-cash accrual of property and equipment	(6.5)	6.8	(22.7)
Discounted secured term loan receivable from contract restructuring	0	$ 47.7	$ 0
ENLC
Supplemental disclosures of cash flow information:
Cash paid for interest	$ 62.6

Other Information (Details)

Other Information (Details) - USD ($)	Dec. 31, 2019	May 31, 2019	Dec. 31, 2018
Other current assets:
Natural gas and NGLs inventory	$ 43,400,000		$ 41,300,000
Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018	0		19,400,000
Secured term loan receivable, discount			1,100,000
Prepaid expenses and other	13,500,000		12,100,000
Natural gas and NGLs inventory, prepaid expenses, and other	56,900,000		72,800,000
Other current liabilities:
Accrued interest	32,600,000		37,300,000
Accrued wages and benefits, including taxes	25,500,000		37,200,000
Accrued ad valorem taxes	28,500,000		28,100,000
Capital expenditure accruals	42,400,000		50,600,000
Onerous performance obligations	0		9,000,000
Short-term lease liability	21,100,000		1,500,000
Suspense producer payments	13,800,000		34,600,000
Operating expense accruals	10,800,000		10,200,000
Other	27,000,000		38,200,000
Other current liabilities	$ 201,700,000		$ 246,700,000
Second Lien Secured Term Loan
Short-term Debt [Line Items]
Maximum borrowing capacity		$ 58,000,000

Uncategorized Items - enlk20191

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 300,000
General Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 231,200,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	1,600,000
Noncontrolling Interest [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 309,800,000
Redeemable Noncontrolling Interest [Member]
Redeemable Noncontrolling Interest, Equity, Carrying Amount	us-gaap_RedeemableNoncontrollingInterestEquityCarryingAmount	9,300,000
Series B Preferred Stock [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 889,300,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	58,700,000
Series C Preferred Stock [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 395,100,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	400,000
Common Unit [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 2,461,100,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	353,100,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 300,000
AOCI Including Portion Attributable to Noncontrolling Interest [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ (2,100,000)