EnLink Midstream Partners (ENLK) 10-K 20 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 13, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Amendment Flag	false
Entity Registrant Name	ENLINK MIDSTREAM PARTNERS, LP
Entity Central Index Key	1,179,060
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		144,535,672
Entity Public Float			$ 2.6

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 99.5	$ 30.8
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	126.3	50.1
Accrued revenue and other	705.9	576.6
Related party	2.1	102.7
Fair value of derivative assets	28.6	6.8
Natural gas and NGLs inventory, prepaid expenses, and other	72.8	39.7
Total current assets	1,035.2	806.7
Property and equipment, net of accumulated depreciation of $2,967.4 and $2,533.0, respectively	6,846.7	6,587
Intangible assets, net of accumulated amortization of $422.2 and $298.7, respectively	1,373.6	1,497.1
Goodwill	190.3	422.3
Investment in unconsolidated affiliates	80.1	89.4
Fair value of derivative assets	4.1	0
Other assets, net	41.3	11.5
Total assets	9,571.3	9,414
Current liabilities:
Accounts payable and drafts payable	105.5	66.9
Accounts payable to related party	4.3	18.4
Accrued gas, NGLs, condensate, and crude oil purchases	500.4	476.1
Fair value of derivative liabilities	21.8	8.4
Installment payable, net of discount of $0.5 at December 31, 2017	0	249.5
Current maturities of long-term debt	399.8	0
Other current liabilities	246.7	222.4
Total current liabilities	1,278.5	1,041.7
Long-term debt	3,919.8	3,467.8
Asset retirement obligations	14.8	14.2
Other long-term liabilities	20	33.9
Deferred tax liability	42.4	46.3
Fair value of derivative liabilities	2.4	0
Redeemable non-controlling interest	9.3	4.6
Partners’ equity:
Common unitholders (353,117,434 and 349,702,372 units issued and outstanding, respectively)	2,117	2,791.6
General partner interest (1,594,974 equivalent units outstanding)	204.4	207.3
Accumulated other comprehensive loss	(2.1)	(2.1)
Non-controlling interest	680.4	549.5
Total partners’ equity	4,284.1	4,805.5
Commitments and contingencies (Note 13)
Total liabilities and partners’ equity	9,571.3	9,414
Series B Preferred Unitholders
Partners’ equity:
Preferred unitholders	889.3	864.1
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, 2018	Dec. 31, 2017
Allowance for bad debt	$ 0.3	$ 0.3
Accumulated depreciation	2,967.4	2,533
Accumulated amortization	$ 422.2	298.7
Purchase price discount, current		$ 0.5
Common units issued (in shares)	353,117,434	349,702,372
Common units outstanding (in shares)	353,117,434	349,702,372
General partner interest, equivalent units outstanding (in shares)	1,594,974	1,594,974
Series B Preferred Unitholders
Preferred units issued (in shares)	58,728,994	57,056,281
Preferred unit outstanding (in shares)	58,728,994	57,056,281
Series C Preferred Unitholders
Preferred unit outstanding (in shares)	400,000	400,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Revenue from contracts with customers		$ 7,693.8
Gain (loss) on derivative activity		5.2	$ (4.2)	$ (11.1)
Total revenues		7,699	5,739.6	4,252.4
Operating costs and expenses:
Cost of sales	[1]	6,008	4,361.5	3,015.5
Operating expenses		453.4	418.7	398.5
General and administrative		130.2	123.5	119.3
Loss on disposition of assets		0.4	0	13.2
Depreciation and amortization		577.3	545.3	503.9
Impairments		365.8	17.1	566.3
Gain on litigation settlement		0	(26)	0
Total operating costs and expenses		7,535.1	5,440.1	4,616.7
Operating income (loss)		163.9	299.5	(364.3)
Other income (expense):
Interest expense, net of interest income		(178.3)	(187.9)	(188.1)
Gain on extinguishment of debt		0	9	0
Income (loss) from unconsolidated affiliates		13.3	9.6	(19.9)
Other income		0.6	0.6	0.3
Total other expense		(164.4)	(168.7)	(207.7)
Income (loss) before non-controlling interest and income taxes		(0.5)	130.8	(572)
Income tax benefit (provision)		2.1	24	(1.3)
Net income (loss)		1.6	154.8	(573.3)
Net income (loss) attributable to non-controlling interest		29.6	5.9	(8.1)
Net income (loss) attributable to ENLK		(28)	148.9	(565.2)
General partner interest in net income		38.6	38.3	39.5
Limited partners’ interest in net income (loss) attributable to ENLK		(180.8)	17.9	(662.1)
Class C partners’ interest in net loss attributable to ENLK		$ 0	$ 0	$ (12.5)
Net income (loss) attributable to ENLK per limited partners’ unit:
Basic common unit (in dollars per share)		$ (0.51)	$ 0.05	$ (1.99)
Diluted common unit (in dollars per share)		$ (0.51)	$ 0.05	$ (1.99)
Series B Preferred Unitholders
Other income (expense):
Preferred interest in net income attributable to ENLK		$ 90.2	$ 86	$ 69.9
Series C Preferred Unitholders
Other income (expense):
Preferred interest in net income attributable to ENLK		24	6.7	0
Product sales
Revenues:
Revenue from contracts with customers		6,512.3	4,358.4	3,008.9
Product sales—related parties
Revenues:
Revenue from contracts with customers		41	144.9	134.3
Midstream services
Revenues:
Revenue from contracts with customers		763.3	552.3	467.2
Midstream services—related parties
Revenues:
Revenue from contracts with customers		$ 377.2	$ 688.2	$ 653.1
[1]	Includes related party cost of sales of $114.1 million, $211.0 million, and $150.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement [Abstract]
Related party cost of sales	$ 114.1	$ 211	$ 150.1

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 1.6	$ 154.8	$ (573.3)
Loss on designated cash flow hedge, net of amortization to interest expense	0	(2.1)	0
Comprehensive income (loss)	1.6	152.7	(573.3)
Comprehensive income (loss) attributable to non-controlling interest	29.6	5.9	(8.1)
Comprehensive income (loss) attributable to ENLK	$ (28)	$ 146.8	$ (565.2)

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Devon	ENLC	Non-Controlling Interest	Non-Controlling InterestENLC	Redeemable Non-Controlling Interest (Temporary Equity)	Accumulated Other Comprehensive Loss	General Partner Interest	Common UnitsLimited Partner	Common UnitsLimited PartnerDevon	Class C Common UnitsLimited Partner	Series B Preferred UnitholdersLimited Partner	Series C Preferred UnitholdersLimited Partner
Beginning balance at Dec. 31, 2015	$ 4,434.5			$ 15.9			$ 0	$ 213.4	$ 4,055.8		$ 149.4	$ 0	$ 0
Beginning balance (in shares) at Dec. 31, 2015								1.6	325.2		7.1	0	0
Increase (Decrease) in Partners' Capital
Issuance of common units	167.5								$ 167.5
Issuance of common units (in shares)									10
Issuance of Preferred Units	724.1											$ 724.1
Issuance of Preferred Units (in shares)												50
Contributions	1.5		$ 237.1		$ 237.1				$ 1.5
Conversion of restricted units for common units, net of units withheld for taxes	(1.2)								$ (1.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)									0.2
Unit-based compensation	30							$ 14.9	$ 15.1
Distributions	(587.2)			(8.2)		$ (1.8)		(58.7)	(520.3)
Distributions (in shares)											0.4	3.2
Conversion of Class C Common Units to common units	0								$ 136.9		$ (136.9)
Conversion of Class C Common Units to common units (in shares)									7.5		(7.5)
Non-controlling interest contributions	207.4			207.4
Net income (loss)	(573.3)			(8.1)				39.5	$ (662.1)		$ (12.5)	$ 69.9
Ending balance at Dec. 31, 2016	4,640.4			444.1			0	$ 209.1	$ 3,193.2		$ 0	$ 794	$ 0
Ending balance (in shares) at Dec. 31, 2016								1.6	342.9		0	53.2	0
Beginning balance at Dec. 31, 2015						7
Increase (Decrease) in Temporary Equity [Roll Forward]
Distributions	(587.2)			(8.2)		(1.8)		$ (58.7)	$ (520.3)
Net income (loss)	(573.3)			(8.1)				39.5	(662.1)		$ (12.5)	$ 69.9
Ending balance at Dec. 31, 2016						5.2
Increase (Decrease) in Partners' Capital
Issuance of common units	106.9								$ 106.9
Issuance of common units (in shares)									6.2
Issuance of Preferred Units	394							0					$ 394
Issuance of Preferred Units (in shares)													0.4
Contributions		$ 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
Unrealized loss on derivatives, net of amortization to interest expense	(2.1)						(2.1)
Net income (loss)	154.8			5.9				38.3	17.9			$ 86	6.7
Ending balance at Dec. 31, 2017	4,805.5			549.5			(2.1)	$ 207.3	$ 2,791.6		$ 0	$ 864.1	$ 395.1
Ending balance (in shares) at Dec. 31, 2017								1.6	349.7		0	57.1	0.4
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			5.9				38.3	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
Fair value adjustment related to redeemable non-controlling interest	(4.1)					4.1			(4.1)
Net income (loss)	1			29		0.6		38.6	(180.8)			$ 90.2	24
Ending balance at Dec. 31, 2018	4,284.1			680.4			$ (2.1)	$ 204.4	$ 2,117		$ 0	$ 889.3	$ 395.1
Ending balance (in shares) at Dec. 31, 2018								1.6	353.1		0	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			$ 29		0.6		$ 38.6	$ (180.8)			$ 90.2	$ 24
Ending balance at Dec. 31, 2018						$ 9.3

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 1.6	$ 154.8	$ (573.3)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	365.8	17.1	566.3
Depreciation and amortization	577.3	545.3	503.9
Loss on disposition of assets	0.4	0	13.2
Non-cash unit-based compensation	40.8	47.8	30
Deferred tax benefit	(3.9)	(26.6)	(0.6)
(Gain) loss on derivatives recognized in net income (loss)	(5.2)	4.2	11.1
Cash settlements on derivatives	(7)	(11.2)	10.5
Gain on extinguishment of debt	0	(9)	0
Amortization of debt issue costs, net (premium) discount of notes and installment payable	4	29.1	53.1
Distribution of earnings from unconsolidated affiliates	15.8	13.3	3.1
(Income) loss from unconsolidated affiliates	(13.3)	(9.6)	19.9
Non-cash revenue from contract restructuring	(45.5)	0	0
Other operating activities	(2.6)	0.6	0.9
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	(114.6)	(189.5)	(117.9)
Natural gas and NGLs inventory, prepaid expenses, and other	(12.2)	(23.7)	10.2
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities	55.4	163.9	132.2
Net cash provided by operating activities	856.8	706.5	662.6
Cash flows from investing activities:
Additions to property and equipment	(843.1)	(790.8)	(663)
Acquisition of business, net of cash acquired	0	0	(769.3)
Proceeds from sale of unconsolidated affiliate investment	0	189.7	0
Proceeds from sale of property	1.9	2.3	93.1
Investment in unconsolidated affiliates	(0.1)	(12.6)	(73.8)
Distribution from unconsolidated affiliates in excess of earnings	6.9	0.2	54.6
Other investing activities	8.1	0.4	0.3
Net cash used in investing activities	(826.3)	(610.8)	(1,358.1)
Cash flows from financing activities:
Proceeds from borrowings	3,904	2,315.9	2,057.8
Payments on borrowings	(3,054)	(2,104.3)	(1,852.7)
Payment of installment payable for EOGP acquisition	(250)	(250)	0
Debt financing costs	(1.7)	(5.5)	(4.6)
Proceeds from issuance of common units	46.1	106.9	167.5
Distribution to common unitholders and to general partner	(613.5)	(604.8)	(579)
Distributions to non-controlling interests	(54.5)	(27.5)	(10)
Contributions by non-controlling interests, including contributions from affiliates of $66.2, $69.1, and $39.5, respectively	156.4	126.4	207.4
Other financing activities	(5.6)	(6.1)	(9.3)
Net cash provided by (used in) financing activities	38.2	(76.5)	701.2
Net increase in cash and cash equivalents	68.7	19.2	5.7
Cash and cash equivalents, beginning of period	30.8	11.6	5.9
Cash and cash equivalents, end of period	99.5	30.8	11.6
Series B Preferred Unitholders
Cash flows from financing activities:
Proceeds from issuance of Preferred Units	0	0	724.1
Distributions to Preferred Unitholders	(65)	(15.9)	0
Series C Preferred Unitholders
Cash flows from financing activities:
Proceeds from issuance of Preferred Units	0	394	0
Distributions to Preferred Unitholders	$ (24)	$ (5.6)	$ 0

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Proceeds from affiliates	$ 156.4	$ 126.4	$ 207.4
Affiliates
Proceeds from affiliates	$ 66.2	$ 69.1	$ 39.5

Organization and Summary of Sig

Organization and Summary of Significant Agreements	12 Months Ended
	Dec. 31, 2018
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 and Nature 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 as successor-in-interest to EMI, which merged with and into ENLC on December 31, 2018. ENLC’s units are traded on the NYSE under the symbol “ENLC.” ENLC’s managing member is a wholly-owned subsidiary of GIP. Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings. At the same time, EMI became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “Business Combination”). In 2015, the Operating Partnership acquired the remaining 50% of the outstanding equity interests in Midstream Holdings. EOGP Acquisition 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. See “ Note 3—Acquisition ” for further discussion. 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 ENLK’s general partner. Simplification of the Corporate Structure On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC , and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “ Note 18—Subsequent Events ” for more information on the Merger and related transactions. As a result of the Merger, ENLC owns all of our outstanding common units. ENLC also owns our general partner and has the power to appoint all of the officers and directors of our general partner. ENLC is managed by its managing member, which is wholly-owned by GIP. Therefore, GIP indirectly controls our general partner, which has the sole authority to manage and operate our business. Accordingly, through its control of our general partner, GIP effectively has the ability to control our management. (b) Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. Our midstream energy asset network includes approximately 11,000 miles of pipelines, 20 natural gas processing plants with approximately 4.9 Bcf/d of processing capacity, seven fractionators with approximately 280,000 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, isobutane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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. (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—P roduct 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 replaces 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. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions): Increase (Decrease) in Revenue Due to Year Ended December 31, 2018 Product sales $ (235 ) Product sales—related parties (52 ) Midstream services (357 ) Midstream services—related parties (27 ) Total $ (671 ) 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 gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) 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 expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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. 2019 $ 252.1 2020 247.9 2021 104.5 2022 95.0 2023 92.9 Thereafter 281.9 Total $ 1,074.3 In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected $135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a $19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us $58.0 million in principal payments in various installments ending in May 2023, with interest accruing on the loan balance at 8.0% per annum beginning in 2020; and (iii) the counterparty granted to us a 1.0% term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized $45.5 million of midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer . 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 year ended December 31, 2018 . As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the year ended December 31, 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) 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 $12.4 million and $7.3 million at December 31, 2018 and 2017 , respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $10.4 million and $5.8 million at December 31, 2018 and 2017 , 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. (e) Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. (f) 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. (g) 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. (h) 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 are as follows (in millions): Year Ended December 31, 2018 2017 Transmission assets $ 1,329.4 $ 1,338.7 Gathering systems 4,410.5 4,040.9 Gas processing plants 3,590.5 3,401.8 Other property and equipment 171.7 157.8 Construction in process 312.0 180.8 Property and equipment 9,814.1 9,120.0 Accumulated depreciation (2,967.4 ) (2,533.0 ) Property and equipment, net of accumulated depreciation $ 6,846.7 $ 6,587.0 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 $453.8 million , $418.2 million , and $386.9 million was recorded for the years ended December 31, 2018 , 2017 , and 2016 , 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, 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 expected 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 . For the year ended December 31, 2016 , we retired or sold net property and equipment of $106.6 million , which was offset by $0.3 million of insurance settlements and $93.1 million of proceeds from the sale of property, resulting in a loss on disposition of assets of $13.2 million . The loss on disposition of assets primarily related to the sale of the NPTL, a 140 -mile natural gas transportation pipeline in North Texas, that resulted in net proceeds of $84.6 million and a loss on sale of $13.4 million . 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, 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 Crude and Condensate 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. There were no impairments on property and equipment recognized for the year ended December 31, 2016. (i) Comprehensive Income (Loss) Comprehensive income (loss) is composed of net income (loss), which consists of 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 the year ended December 31, 2018 and 2017, we reclassified an immaterial amount of losses from accumulated other comprehensive income (loss) to earnings. For additional information, see “ Note 11—Derivatives .” (j) 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. For additional information, see “ Note 9—Investment in Unconsolidated Affiliates .” (k) 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, 2018, 2017, and 2016 relate to ENLC’s 16.1% ownership of EOGP, 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. (l) Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acqui

Acquisition

Acquisition	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisition	(3) Acquisition On January 7, 2016, ENLK and ENLC acquired an 83.9% and 16.1% voting interest, respectively, in EOGP for aggregate consideration of approximately $1.4 billion . Upon closing of the acquisition on January 7, 2016, the first installment of $1.02 billion for the acquisition was paid. The second and final installments, each equal to $250.0 million , were paid in January 2017 and January 2018, respectively. The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by ENLK, which was primarily derived from the issuance of Series B Preferred Units, (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and (c) approximately $22.2 million in cash paid by ENLC . The transaction was accounted for using the acquisition method. The following table presents the considerations ENLK and ENLC paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration: Cash $ 783.6 Total installment payable, net of discount of $79.1 million 420.9 Contribution from ENLC 237.1 Total consideration $ 1,441.6 Purchase Price Allocation: Assets acquired: Current assets (including $12.8 million in cash) $ 23.0 Property and equipment 406.1 Intangibles 1,051.3 Liabilities assumed: Current liabilities (38.8 ) Total identifiable net assets $ 1,441.6 The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years. We incurred a total of $3.7 million of direct transaction costs for the year ended December 31, 2016. These costs are included in general and administrative costs in the accompanying consolidated statements of operations. For the period from January 7, 2016 to December 31, 2016, we recognized $246.1 million of revenues and $34.1 million of net loss, of which $5.5 million is attributable to non-controlling interests, related to the assets acquired.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	(4) 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. The table below provides a summary of our change in carrying amount of goodwill (in millions) for the year ended December 31, 2018, by assigned reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amounts of goodwill. Texas Oklahoma Totals Year Ended December 31, 2018 Balance, beginning of period $ 232.0 $ 190.3 $ 422.3 Impairment (232.0 ) — (232.0 ) Balance, end of period $ — $ 190.3 $ 190.3 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 multiples, and estimated future cash flows, including volume and price forecasts 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 estimated fair value of our reporting units may be impacted in the future by a decline in our unit price or a prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units. Prior to January 2017, if a goodwill impairment test was elected or required, we performed a two-step goodwill impairment test. The first step involved comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeded its fair value, the second step of the process involved comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeded the implied fair value of that goodwill, the excess of the carrying value over the implied fair value was recognized as an impairment. Effective January 2017, we elected to early adopt ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)— Simplifying the Test for Goodwill Impairment “ASU 2017-04”), which simplified the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350, Intangibles — Goodwill and Other . Therefore, our annual impairment test as of October 31, 2017 was performed according to ASU 2017-04. 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 Texas reporting unit in the amount of $232.0 million 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. Substantially all of the goodwill for our Texas reporting unit was recorded as a result of our Business Combination in March 2014. We concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for the Oklahoma reporting unit 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 . Goodwill Impairment Analysis for the Year Ended December 31, 2016 During February 2016, we determined that continued weakness in the overall energy sector, driven by low commodity prices together with a decline in our unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized in the first quarter of 2016 and is included as impairments in the consolidated statement of operations for the year ended December 31, 2016. We concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis. During our annual impairment test for 2016, performed as of October 31, 2016, we determined that no further impairments were required for the year ended December 31, 2016 . 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, 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 Year Ended December 31, 2016 Customer relationships, beginning of period $ 744.5 $ (54.6 ) $ 689.9 Acquisitions 1,051.3 — 1,051.3 Amortization expense — (117.0 ) (117.0 ) Customer relationships, end of period $ 1,795.8 $ (171.6 ) $ 1,624.2 For the years ended December 31, 2018, 2017, and 2016, 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 discounted cash flow assumptions by management consistent with those utilized in our goodwill impairment analysis. The weighted average amortization period for intangible assets is 15.0 years . Amortization expense was $123.5 million , $127.1 million , and $117.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2019 $ 123.7 2020 123.7 2021 123.7 2022 123.7 2023 123.6 Thereafter 755.2 Total $ 1,373.6

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	(5) Related Party Transactions Simplification of the Corporate Structure On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC , and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “ Note 18—Subsequent Events ” for more information on the Merger and related transactions. 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 , 2017 , and 2016 , related party transactions with Devon accounted for 5.4% , 14.4% , and 18.5% of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million as of December 31, 2017 . Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million as of December 31, 2017 . Management believes these transactions are executed on terms that are fair and reasonable. The amounts from related party transactions are specified in the accompanying consolidated financial statements. Gathering, Processing, and Transportation Agreements Associated with Our Business Combination with Devon As described in “ Note 1—Organization and Summary of Significant Agreements ,” Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. On January 1, 2014, in connection with the consummation of the Business Combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings (“EnLink Midstream Services”), entered into 10 -year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides 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 Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford, and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10 -year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration, and redelivery services, as applicable, for natural gas delivered by Gas Services to another of our gathering systems in the Barnett Shale. These agreements provide Midstream Holdings 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 Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford, and Arkoma-Woodford Shales during each calendar quarter. From January 1, 2018 to July 18, 2018, we recognized $321.3 million of revenue under these agreements. For the years ended December 31, 2017 and 2016 , we recognized $615.5 million and $611.8 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 and $46.2 million for the years ended December 31, 2017 and 2016 , respectively. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings 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 Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ 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. In connection with the closing of the Business Combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline. 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 has an MVC that will remain in place during each calendar quarter for four years and 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 , $100.4 million , and $34.4 million of our combined revenues from January 1, 2018 to July 18, 2018 and for the years ended December 31, 2017 and 2016 , respectively. Other Commercial Relationships with Devon As noted above, we continue to maintain a customer relationship with Devon originally established prior to the Business Combination 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 comprise $66.6 million , $78.0 million , and $107.2 million of our combined revenue from January 1, 2018 to July 18, 2018 and for the years ended December 31, 2017 and 2016 , respectively. VEX Transportation Agreement In connection with our acquisition of the VEX assets from Devon, we became party to a five -year transportation services agreement with Devon pursuant to which we provide transportation services to Devon on the VEX pipeline. This agreement includes a five -year MVC with Devon. The MVC was executed in June 2014, and the initial term expires July 2019. This agreement accounted for approximately $3.5 million , $17.8 million , and $18.7 million of service revenues from January 1, 2018 to July 18, 2018 and for the years ended December 31, 2017 and 2016 , respectively. Acacia Transportation Agreement In connection with the consummation of the Business Combination, 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 Texas. This agreement accounted for approximately $4.9 million , $13.8 million , and $15.2 million of our combined revenues from January 1, 2018 to July 18, 2018 and for the years ended December 31, 2017 and 2016 , respectively. GCF Interest In connection with the consummation of the Business Combination and the GIP Transaction, a wholly-owned subsidiary of Devon transferred to us its 38.75% general partner interest in GCF. Our interest in GCF contributed approximately $10.5 million , $12.6 million , and $3.4 million to our income from unconsolidated affiliate investment from January 1, 2018 to July 18, 2018 and for the years ended December 31, 2017 and 2016 , respectively. Cedar Cove Joint Venture On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. Under a 15 -year, fixed-fee agreement, all gas gathered by the Cedar Cove JV will be processed at our Central Oklahoma processing system. For the period from November 9, 2016 through December 31, 2016 , revenue generated from processing gas and cost of sales from the Cedar Cove JV was immaterial. 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. In addition, for the years ended December 31, 2018 and December 31, 2017 , we recorded cost of sales of $44.1 million and $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 an accounts receivable balance related to transactions with the Cedar Cove JV of $0.7 million at December 31, 2018 . Additionally, we had an accounts payable balance related to transactions with the Cedar Cove JV of $4.3 million at December 31, 2018 . The accounts receivable and payable balances related to transactions with the Cedar Cove JV were immaterial at December 31, 2017 . Transactions with ENLC ENLC paid us $2.5 million , $2.4 million , and $2.3 million as reimbursement during the years ended December 31, 2018 , 2017 , and 2016 , respectively, to cover its portion of administrative and compensation costs for officers and employees that perform services for ENLC. This reimbursement is evaluated on an annual basis. Officers and employees that perform services for ENLC provide 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) is allocated to ENLC for reimbursement based on these estimates. In addition, an administrative burden is 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. ENLC paid us $26.6 million , $48.4 million , and $31.5 million for their interest in EOGP’s capital expenditures for the years ended December 31, 2018 , 2017 , and 2016 , respectively. ENLC paid its contribution for EOGP’s capital expenditures to us monthly, net of EOGP’s adjusted EBITDA distributable to ENLC , which is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from us. Following the Merger, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership. See “ Note 18—Subsequent Events ” for more information regarding these transactions. Tax Sharing Agreement In connection with the consummation of the Business Combination, 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 the years ended December 31, 2017 and 2016 we incurred approximately $0.4 million , $1.2 million , and $2.3 million , respectively, in taxes that are subject to the tax sharing agreement. Effective July 18, 2018, ENLK, ENLC, and Devon signed a supplemental agreement to continue the tax sharing agreement.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of December 31, 2018 and 2017 , long-term debt consisted of the following (in millions): December 31, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt 2.70% Senior unsecured notes due 2019 (1) $ 400.0 $ — $ 400.0 $ 400.0 $ (0.1 ) $ 399.9 Term Loan due 2021 (2) 850.0 — 850.0 — — — 4.40% Senior unsecured notes due 2024 550.0 1.8 551.8 550.0 2.2 552.2 4.15% Senior unsecured notes due 2025 750.0 (0.9 ) 749.1 750.0 (1.0 ) 749.0 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.6 ) 499.4 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 (6.2 ) 443.8 450.0 (6.5 ) 443.5 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 500.0 (0.1 ) 499.9 Debt classified as long-term $ 4,350.0 $ (6.1 ) 4,343.9 $ 3,500.0 $ (6.3 ) 3,493.7 Debt issuance cost (3) (24.3 ) (25.9 ) Less: Current maturities of long-term debt (1) (399.8 ) — Long-term debt, net of unamortized issuance cost $ 3,919.8 $ 3,467.8 (1) The 2.70% senior unsecured notes mature 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 . (2) 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 . (3) Net of amortization of $15.3 million and $12.0 million at December 31, 2018 and 2017 , respectively. Maturities Maturities for the long-term debt as of December 31, 2018 are as follows (in millions): 2019 $ 400.0 2020 — 2021 850.0 2022 — 2023 — Thereafter 3,100.0 Subtotal 4,350.0 Less: net discount (6.1 ) Less: debt issuance cost (24.3 ) Less: current maturities of long-term debt (399.8 ) Long-term debt, net of unamortized issuance cost $ 3,919.8 ENLK Credit Facility Prior to the closing of the Merger, we had a $1.5 billion unsecured revolving credit facility that matured on March 6, 2020, which included a $500.0 million letter of credit subfacility . Upon the closing of the Merger, the ENLK Credit Facility was repaid and canceled, and all indebtedness thereunder was repaid with borrowings under the Consolidated Credit Facility at ENLC. Borrowings under the ENLK Credit Facility bore interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75% ) 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 0.0% to 0.75% ). The applicable margins varied depending on our credit rating. On June 20, 2018, we amended the change of control provisions of the ENLK Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLK Credit Facility). As of December 31, 2018 and 2017 , we had no borrowings under the ENLK Credit Facility, and there were $9.8 million in outstanding letters of credit for each period, respectively. Consolidated Credit Facility In connection with the Merger, we refinanced our existing revolving credit facilities at ENLK and ENLC. As of December 31, 2018, we had a $1.5 billion facility at ENLK and a $250.0 million facility at ENLC. Following the Merger, we have combined these credit facilities into one $1.75 billion credit facility at ENLC. Following the Merger, ENLK guaranteed the obligations of ENLC under the Consolidated Credit Facility. For additional information, refer to “ Note 18—Subsequent Events .” At December 31, 2018 , ENLC was in compliance with and expects to be in compliance with the covenants in the Consolidated Credit Facility for at least the next twelve months. Term Loan On December 11, 2018, ENLK entered into the Term Loan with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto. Also, on December 11, 2018, ENLK borrowed $850.0 million under the Term Loan and used the net proceeds to repay obligations outstanding under the ENLK Credit Facility. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. 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 2.50 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 5.00 to 1.00 . If the borrower consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the borrower can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.50 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Term Loan bear interest at the borrower’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75% ) 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 0.00% to 0.75% ). The applicable margins vary depending on ENLC’s debt rating. Upon breach by the borrower of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately. At December 31, 2018 , 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. 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 in the Business Combination. The interest payments on the 2022 Notes were due semi-annually in arrears in June and December. As a result of the Business Combination, 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 mature 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 2019 Notes, 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. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes. 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. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes . Senior Unsecured Note 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 2019 Notes April 1, 2019 Prior to March 1, 2019 20 Basis Points 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 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 Note Indentures The indentures governing the senior unsecured notes contain covenants that, among other things, limit our ability to create or incur certain liens or consolidate, merge, or transfer all or substantially all of our 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 us. 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, 2018 , we 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, 2018
Income Tax Disclosure [Abstract]
Income Taxes	(7) Income Taxes The components of our income tax provision (benefit) are as follows (in millions): Year Ended December 31, 2018 2017 2016 Current income tax provision $ 1.8 $ 2.6 $ 1.9 Deferred tax benefit (3.9 ) (26.6 ) (0.6 ) Total income tax provision (benefit) $ (2.1 ) $ (24.0 ) $ 1.3 Net income for financial statement purposes may differ significantly from taxable income 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 $42.4 million and $46.3 million existed at December 31, 2018 and 2017 , respectively. Deferred tax liabilities as of December 31, 2018 and 2017 included $38.7 million and $38.8 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 year ended December 31, 2016, we recognized $1.5 million of previously recorded unrecognized income tax benefit. For the three years ended December 31, 2018 , 2017 , and 2016 , 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, 2018 , tax years 2014 through 2018 remain subject to examination by various taxing authorities.

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2018
Partners' Capital Notes [Abstract]
Partners' Capital	(8) Partners' Capital (a) Issuance of Common Units In November 2014, we entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC 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. For the year ended December 31, 2016, we sold an aggregate of 10.0 million common units, generating proceeds of $167.5 million (net of $1.7 million of commissions). 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 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) Class C Common Units As of December 31, 2015, there were 7,075,433 Class C Common Units issued and outstanding. The Class C Common Units were substantially similar in all respects to our common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by our general partner in its sole discretion. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units were converted into common units on a one -for-one basis on May 13, 2016. (c) 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”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund our portion of the purchase price payable in connection with the acquisition of our EOGP assets. Affiliates of Goldman Sachs and affiliates of TPG own interests in the general partner of Enfield. Prior to the close of the Merger on January 25, 2019, the Series B Preferred Units were convertible into our common units on a one -for-one basis, subject to certain adjustments, (a) in full, at our option, if the volume weighted average price of a common unit over the 30 -trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) was greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of our general partner or the managing member of ENLC , all of the Series B Preferred Units would have automatically converted into a number of common units equal to the greater of (i) the number of common units into which the Series B Preferred Units would then convert and (ii) the number of Series B Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP. The Series B Preferred Units will continue to be issued and outstanding following the Merger, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. Subsequent to the modification, Series B Preferred Units will be 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 are 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 common units over the Cash Distribution Component, divided by (ii) the issue price of $15.00 . Beginning with the quarter ending March 31, 2019, the holder of the Series B Preferred Units will be 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”) will equal 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 will consist 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. For the years ended December 31, 2018 , 2017 , and 2016 , $90.2 million , $86.0 million , and $69.9 million of income was allocated to the Series B Preferred Units, respectively. A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2018 , 2017 , and 2016 is provided below: Declaration period Distribution Cash distribution Date paid/payable 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 2016 First Quarter of 2016 992,445 $ — May 12, 2016 Second Quarter of 2016 1,083,589 $ — August 11, 2016 Third Quarter of 2016 1,106,616 $ — November 10, 2016 Fourth Quarter of 2016 1,130,131 $ — February 13, 2017 (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. Income is allocated to the Series C Preferred Units in an amount equal to the earned distributions for the respective reporting period. For the years ended December 31, 2018 and 2017 , $24.0 million and $6.7 million of income, respectively, was allocated to the Series C Preferred Units. 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% . For the years ended December 31, 2018 and 2017 , we made distributions of $24.0 million and $5.6 million to holders of Series C Preferred Units, respectively. Following the Merger, the Series C Preferred Units remained 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. As of December 31, 2018, 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 our 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 close of the Merger, our general partner’s incentive distribution rights in ENLK were eliminated. See “ Note 18—Subsequent Events ” for more information regarding the Merger and related transactions. A summary of the distribution activity relating to the common units for the years ended December 31, 2018 , 2017 , and 2016 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 2016 First Quarter of 2016 $ 0.390 May 12, 2016 Second Quarter of 2016 $ 0.390 August 11, 2016 Third Quarter of 2016 $ 0.390 November 11, 2016 Fourth Quarter of 2016 $ 0.390 February 13, 2017 (f) Earnings Per Unit and Dilution Computations As required under ASC 260, Earnings Per Share , unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per limited partner unit for the periods presented (in millions, except per unit amounts): Year Ended December 31, 2018 2017 2016 Distributed earnings allocated to: Common units (1) $ 548.1 $ 541.2 $ 520.0 Unvested restricted units (1) 4.4 4.0 3.5 Total distributed earnings $ 552.5 $ 545.2 $ 523.5 Undistributed loss allocated to: Common units $ (727.5 ) $ (523.5 ) $ (1,177.6 ) Unvested restricted units (5.8 ) (3.8 ) (8.0 ) Total undistributed loss $ (733.3 ) $ (527.3 ) $ (1,185.6 ) Net income (loss) allocated to: Common units $ (179.4 ) $ 17.7 $ (657.6 ) Unvested restricted units (1.4 ) 0.2 (4.5 ) Total limited partners’ interest in net income (loss) $ (180.8 ) $ 17.9 $ (662.1 ) Basic and diluted net income (loss) per unit: Basic $ (0.51 ) $ 0.05 $ (1.99 ) Diluted $ (0.51 ) $ 0.05 $ (1.99 ) ___________________________ (1) Represents distribution activity consistent with the distribution activity table in section “(e) Common Unit Distributions” above. The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the years ended December 31, 2018 , 2017 , and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) 351.3 346.9 333.3 Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) 351.3 346.9 333.3 Dilutive effect of non-vested restricted units (2) — 1.4 — Total weighted average limited partner diluted common units outstanding 351.3 348.3 333.3 ___________________________ (1) Weighted average limited partner basic common units outstanding for the years ended December 31, 2016 included the weighted average impact of 2,740,273 Class C Units, which converted into common units on May 13, 2016. (2) All common unit equivalents were antidilutive for the years ended December 31, 2018 and 2016 because the limited partners were allocated a net loss. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. Prior to the closing of the Merger and for the years ended December 31, 2018, 2017, and 2016, 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’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 our net income (loss) adjusted for ENLC’s unit-based compensation specifically allocated to our general partner. The net income (loss) allocated to the general partner is as follows (in millions): Year Ended December 31, 2018 2017 2016 Income allocation for incentive distributions $ 59.5 $ 58.9 $ 56.8 Unit-based compensation attributable to ENLC’s restricted units (20.3 ) (21.0 ) (14.7 ) General partner share of net income (loss) (0.6 ) 0.4 (2.6 ) General partner interest in net income $ 38.6 $ 38.3 $ 39.5

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates Our unconsolidated investments consisted of: • a 38.75% ownership interest in GCF at December 31, 2018 , 2017 , and 2016 ; • an approximate 30.0% ownership in the Cedar Cove JV at December 31, 2018 , 2017, and 2016. On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc.; and • an approximate 31% ownership interest in HEP at December 31, 2016 , which was sold in March 2017 for aggregate net proceeds of $189.7 million . The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2018 2017 2016 GCF Distributions $ 22.3 $ 12.7 $ 7.5 Equity in income $ 15.8 $ 12.6 $ 3.4 HEP Contributions (1) $ — $ — $ 45.0 Distributions (2) $ — $ — $ 50.2 Equity in income (loss) (3) $ — $ (3.4 ) $ (23.3 ) Cedar Cove JV Contributions $ 0.1 $ 12.6 $ 28.8 Distributions $ 0.4 $ 0.8 $ — Equity in income $ (2.5 ) $ 0.4 $ — Total Contributions (1) $ 0.1 $ 12.6 $ 73.8 Distributions (2) $ 22.7 $ 13.5 $ 57.7 Equity in income (loss) (3) $ 13.3 $ 9.6 $ (19.9 ) ___________________________ (1) Contributions for the year ended December 31, 2016 included $32.7 million of contributions to HEP for preferred units issued by HEP. These preferred units were redeemed during the third quarter 2016. (2) Distributions for the year ended December 31, 2016 included a redemption of $32.7 million of preferred units issued by HEP. (3) Included losses of $3.4 million and $20.1 million for the years ended December 31, 2017 and 2016 , respectively, related to the sale of our HEP interests. The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2018 and 2017 (in millions): December 31, 2018 December 31, 2017 GCF $ 41.9 $ 48.4 Cedar Cove JV 38.2 41.0 Total investments in unconsolidated affiliates $ 80.1 $ 89.4

Employee Incentive Plans

Employee Incentive Plans	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Incentive Plans	(10) Employee Incentive Plans (a) Long-Term Incentive Plans We and ENLC each have similar unit-based compensation payment plans for officers and employees. We have historically granted unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”) , and ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”) . As of the effective time 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 common units representing limited partner interests in ENLK subject to such Legacy ENLK Awards will convert into common units representing limited liability company interests in ENLC using the exchange ratio (as defined in the Merger Agreement) as the conversion rate. In connection with the consummation of the Merger, no additional awards will be granted under the GP Plan. We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to ENLC’s 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, 2018 2017 2016 Cost of unit-based compensation charged to general and administrative expense $ 30.0 $ 37.1 $ 23.4 Cost of unit-based compensation charged to operating expense 10.8 10.7 6.6 Total unit-based compensation expense $ 40.8 $ 47.8 $ 30.0 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’s Restricted Incentive Units ENLK restricted incentive units are 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, 2018 is provided below: Year Ended December 31, 2018 EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,980,224 $ 15.81 Granted (1) 1,590,100 15.27 Vested (1)(2) (835,115 ) 19.68 Forfeited (178,939 ) 12.75 Non-vested, end of period 2,556,270 $ 14.43 Aggregate intrinsic value, end of period (in millions) $ 28.1 ___________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2018, our general partner granted 200,753 restricted incentive units with a fair value of $3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units include 261,063 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the years ended December 31, 2018 , 2017 , and 2016 is provided below (in millions): Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2018 2017 2016 Aggregate intrinsic value of units vested $ 13.1 $ 16.6 $ 4.1 Fair value of units vested $ 16.4 $ 22.6 $ 9.5 As of December 31, 2018 , there was $18.4 million of unrecognized compensation cost related to non-vested ENLK restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.8 years . (c) EnLink Midstream Partners, LP’s Performance Units Our general partner has granted performance awards under the GP Plan. The performance award agreements provided that the vesting of 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”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units vested 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. At the end of the vesting period, recipients received distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranged from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. As of the effective time of the Merger, the performance metric for such performance awards was modified such that the performance metric 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 after the effective time of the Merger . 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 our common units and the designated Peer Companies’ securities; (iii) an estimated ranking of us among the designated Peer Companies; and (iv) the distribution yield. The fair value of the performance unit on the date of grant was expensed over a vesting period of approximately three years . The following table presents a summary of the grant-date fair value of performance units granted and the related assumptions by performance unit grant date: EnLink Midstream Partners, LP Performance Units: March 2018 March 2017 October 2016 February 2016 January 2016 TSR price $15.44 $17.55 $17.71 $14.82 $14.82 Risk-free interest rate 2.38 % 1.62 % 0.91 % 0.89 % 1.10 % Volatility factor 43.85 % 43.94 % 44.62 % 42.33 % 39.71 % Distribution yield 10.50 % 8.70 % 8.80 % 19.20 % 12.10 % The following table presents a summary of the performance units: Year Ended December 31, 2018 EnLink Midstream Partners, LP Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 585,285 $ 20.52 Granted 256,345 19.24 Vested (1) (313,610 ) 24.43 Forfeited (76,351 ) 16.62 Non-vested, end of period 451,669 $ 17.74 Aggregate intrinsic value, end of period (in millions) $ 5.0 (1) Vested units included 112,101 units withheld for payroll taxes paid on behalf of employees and 120,250 units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes. 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 year ended December 31, 2018 is provided below (in millions). No performance units vested for the years ended 2017 and 2016 . EnLink Midstream Partners, LP Performance Units: Year Ended December 31, 2018 Aggregate intrinsic value of units vested $ 5.0 Fair value of units vested $ 7.7 As of December 31, 2018 , there was $6.1 million of unrecognized compensation expense that related to non-vested performance units. That cost is expected to be recognized over a weighted-average period of 1.7 years . In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to, among other things: (i) provide that the awards granted thereunder did not vest due to the closing of the GIP Transaction and (ii) increase the minimum vesting of units from zero to 100% as described in our Current Report on Form 8-K filed with the Securities and Exchange Commission (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 $2.3 million compensation cost over the life of these ENLK performance units. (d) EnLink Midstream, LLC’s 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, 2018 is provided below: Year Ended December 31, 2018 EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,889,310 $ 16.33 Granted (1) 1,473,195 15.76 Vested (1)(2) (769,848 ) 21.40 Forfeited (166,790 ) 12.74 Non-vested, end of period 2,425,867 $ 14.62 Aggregate intrinsic value, end of period (in millions) $ 23.0 ___________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted 194,185 restricted incentive units with a fair value of $3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units include 244,123 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2018 , 2017 , and 2016 is provided below (in millions): Year Ended December 31, EnLink Midstream, LLC Restricted Incentive Units: 2018 2017 2016 Aggregate intrinsic value of units vested $ 12.8 $ 15.3 $ 4.1 Fair value of units vested $ 16.5 $ 22.2 $ 12.4 As of December 31, 2018 , there was $17.9 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. That cost is expected to be recognized over a weighted average period of 1.8 years . (e) EnLink Midstream, LLC’s Performance Units ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain TSR performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranges from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. As of the effective time of the Merger, the performance metric for such performance awards was modified such that the performance metric 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 after the effective time of the Merger. 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’ securities; (iii) an estimated ranking of 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 . The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream, LLC Performance Units: March 2018 March 2017 October 2016 February 2016 January 2016 TSR price $ 16.55 $ 18.29 $ 16.75 $ 15.38 $ 15.38 Risk-free interest rate 2.38 % 1.62 % 0.91 % 0.89 % 1.10 % Volatility factor 51.36 % 52.07 % 52.89 % 52.05 % 46.02 % Distribution yield 6.70 % 5.40 % 6.10 % 14.00 % 8.60 % The following table presents a summary of the performance units: Year Ended December 31, 2018 EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 548,839 $ 22.14 Granted 223,865 21.63 Vested (1) (283,637 ) 27.25 Forfeited (70,918 ) 17.75 Non-vested, end of period 418,149 $ 19.15 Aggregate intrinsic value, end of period (in millions) $ 4.0 (1) Vested units included 100,109 units withheld for payroll taxes paid on behalf of employees and 109,819 units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes. 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 year ended December 31, 2018 is provided below (in millions). No performance units vested for the years ended 2017 and 2016 . EnLink Midstream, LLC Performance Units: Year Ended December 31, 2018 Aggregate intrinsic value of units vested $ 4.7 Fair value of units vested $ 7.7 As of December 31, 2018 , there was $5.9 million of unrecognized compensation expense that related to non-vested performance units. That cost is expected to be recognized over a weighted-average period of 1.6 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 . (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 $8.3 million , $7.6 million , and $7.4 million were made to the plan for the years ended December 31, 2018 , 2017 , and 2016 , respectively.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) Derivatives Interest Rate Swaps 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. Prior to 2017, we did not designate interest rate swaps as hedges and, therefore, included the associated settlement gains and losses as interest expense, net of interest income on the consolidated statements of operations. In May 2017, we entered into an interest rate swap in connection with the issuance of our 2047 Notes. In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. We have no open interest rate swap positions as of December 31, 2018 . In addition, the settlement loss is included as an operating cash outflow on the consolidated statement of cash flows for the year ended December 31, 2017. For the years ended December 31, 2018 and 2017 , we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize and additional $0.1 million of interest expense out of accumulated other comprehensive income (loss) over the next twelve months. In July 2016, we entered into an interest rate swap in connection with the issuance of the 2026 Notes. We did not designate this swap as a cash flow hedge. Upon settlement of the interest rate swap in July 2016, we recorded the associated $0.4 million gain on settlement as interest expense, net of interest income in the consolidated statement of operations for the year ended December 31, 2016. 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, 2018 2017 2016 Change in fair value of derivatives $ 10.1 $ 4.7 $ (20.1 ) Realized gain (loss) on derivatives (4.9 ) (8.9 ) 9.0 Gain (loss) on derivative activity $ 5.2 $ (4.2 ) $ (11.1 ) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): December 31, 2018 December 31, 2017 Fair value of derivative assets — current $ 28.6 $ 6.8 Fair value of derivative assets — long-term 4.1 — Fair value of derivative liabilities — current (21.8 ) (8.4 ) Fair value of derivative liabilities — long-term (2.4 ) — Net fair value of derivatives $ 8.5 $ (1.6 ) 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, 2018 (in millions). The remaining term of the contracts extend no later than December 2022. December 31, 2018 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (29.0 ) $ 4.5 NGL (long contracts) Swaps Gallons 7.7 0.1 Natural Gas (short contracts) Swaps MMBtu (9.0 ) (1.6 ) Natural Gas (long contracts) Swaps MMBtu 14.9 (1.5 ) Crude and Condensate (short contracts) Swaps MMbbls (12.9 ) 23.6 Crude and Condensate (long contracts) Swaps MMbbls 1.0 (16.6 ) Total fair value of derivatives $ 8.5 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 $32.7 million as of December 31, 2018 would be reduced to $9.4 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, 2018
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. Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2018 December 31, 2017 Commodity Swaps (1) $ 8.5 $ (1.6 ) ___________________________ (1) The fair values of derivative contracts included in assets or liabilities for risk management activities 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, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value Long-term debt, including current maturities of long-term debt (1) $ 4,319.6 $ 3,953.6 $ 3,467.8 $ 3,575.6 Installment Payables $ — $ — $ 249.5 $ 249.6 Obligations under capital lease $ 2.5 $ 2.2 $ 4.1 $ 3.4 Secured term loan receivable $ 51.1 $ 51.1 $ — $ — ___________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of $24.3 million and $25.9 million at December 31, 2018 and 2017 , respectively. The respective fair values do not factor in debt issuance costs. The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. As of December 31, 2018 and 2017 , we had total borrowings under senior unsecured notes of $3.5 billion for each period, respectively, maturing between 2019 and 2047 with fixed interest rates ranging from 2.7% to 5.6% . The fair values of all senior unsecured notes and installment payables as of December 31, 2018 and 2017 were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases and 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, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(13) Commitments and Contingencies (a) Leases—Lessee We have operating leases for office space, office, and field equipment. The following table summarizes our remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions): 2019 $ 14.1 2020 10.3 2021 8.7 2022 8.6 2023 8.8 Thereafter 49.8 Total $ 100.3 Operating lease rental expense was approximately $52.5 million , $54.5 million , and $59.6 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. (b) 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. (c) 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 . (d) 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 a party to a number of 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 results of operations, financial condition, 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, 2018
Segment Reporting [Abstract]
Segment Information	(14) Segment Information Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. As of December 31, 2018, our reportable segments consisted of the following: natural gas gathering, processing, transmission, and fractionation operations located in North Texas and the Permian Basin primarily in West Texas (“Texas”), natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”), and crude rail, truck, pipeline, and barge facilities in West Texas, South Texas, Louisiana, Oklahoma, and the Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers. We evaluate the performance of our operating segments based on segment profits. Corporate assets consist primarily of cash, property, and equipment, including software, for general corporate support, debt financing costs, and unconsolidated affiliate investments in GCF and the Cedar Cove JV as of December 31, 2018 , 2017 , and 2016 . As of December 31, 2016, our Corporate assets also included our unconsolidated affiliate investment in HEP. In December 31, 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale in March 2017. 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 year ended December 31, 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. Summarized financial information for our reportable segments is shown in the following tables (in millions): Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2018 Natural gas sales $ 292.9 $ 531.1 $ 189.7 $ — $ — $ 1,013.7 NGL sales 28.6 2,786.3 25.2 0.9 — 2,841.0 Crude oil and condensate sales — 0.5 0.7 2,656.4 — 2,657.6 Product sales 321.5 3,317.9 215.6 2,657.3 — 6,512.3 Natural gas sales—related parties — — 2.5 — — 2.5 NGL sales—related parties 503.5 47.4 590.8 — (1,104.3 ) 37.4 Crude oil and condensate sales—related parties 49.3 0.3 85.6 3.3 (137.4 ) 1.1 Product sales—related parties 552.8 47.7 678.9 3.3 (1,241.7 ) 41.0 Gathering and transportation 177.9 68.8 149.1 3.1 — 398.9 Processing 101.0 3.3 122.8 — — 227.1 NGL services — 59.6 — — — 59.6 Crude services — — 0.6 66.5 — 67.1 Other services 9.6 0.6 0.2 0.2 — 10.6 Midstream services 288.5 132.3 272.7 69.8 — 763.3 Gathering and transportation—related parties 122.7 — 80.6 — — 203.3 Processing—related parties 108.6 — 48.4 — — 157.0 NGL services—related parties — 3.3 — — (3.3 ) — Crude services—related parties — — 1.5 14.9 — 16.4 Other services—related parties 0.5 — — — — 0.5 Midstream services—related parties 231.8 3.3 130.5 14.9 (3.3 ) 377.2 Revenue from contracts with customers 1,394.6 3,501.2 1,297.7 2,745.3 (1,245.0 ) 7,693.8 Cost of sales (753.9 ) (3,158.7 ) (744.0 ) (2,596.4 ) 1,245.0 (6,008.0 ) Operating expenses (180.6 ) (108.3 ) (89.2 ) (75.3 ) — (453.4 ) Gain on derivative activity — — — — 5.2 5.2 Segment profit $ 460.1 $ 234.2 $ 464.5 $ 73.6 $ 5.2 $ 1,237.6 Depreciation and amortization $ (216.2 ) $ (122.7 ) $ (178.1 ) $ (51.6 ) $ (8.7 ) $ (577.3 ) Impairments $ (232.0 ) $ (24.6 ) $ — $ (109.2 ) $ — $ (365.8 ) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 249.4 $ 47.0 $ 412.5 $ 135.7 $ 5.3 $ 849.9 Total assets $ 2,925.3 $ 2,347.9 $ 3,116.5 $ 959.3 $ 222.3 $ 9,571.3 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2017 Product sales $ 325.0 $ 2,529.6 $ 128.8 $ 1,375.0 $ — $ 4,358.4 Product sales—related parties 500.3 45.0 349.4 0.8 (750.6 ) 144.9 Midstream services 116.3 220.6 155.0 60.4 — 552.3 Midstream services—related parties 424.3 136.4 241.6 17.4 (131.5 ) 688.2 Cost of sales (772.3 ) (2,618.1 ) (522.9 ) (1,330.3 ) 882.1 (4,361.5 ) Operating expenses (172.7 ) (101.3 ) (64.6 ) (80.1 ) — (418.7 ) Loss on derivative activity — — — — (4.2 ) (4.2 ) Segment profit (loss) $ 420.9 $ 212.2 $ 287.3 $ 43.2 $ (4.2 ) $ 959.4 Depreciation and amortization $ (215.2 ) $ (116.1 ) $ (156.6 ) $ (47.5 ) $ (9.9 ) $ (545.3 ) Impairments $ — $ (0.8 ) $ — $ (16.3 ) $ — $ (17.1 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 145.4 $ 75.1 $ 442.1 $ 79.1 $ 26.4 $ 768.1 Total assets $ 3,094.8 $ 2,408.5 $ 2,836.7 $ 929.5 $ 144.5 $ 9,414.0 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2016 Product sales $ 237.2 $ 1,632.5 $ 48.5 $ 1,090.7 $ — $ 3,008.9 Product sales—related parties 287.6 57.8 120.4 1.5 (333.0 ) 134.3 Midstream services 104.2 215.4 82.2 65.4 — 467.2 Midstream services—related parties 439.3 95.8 185.9 18.9 (86.8 ) 653.1 Cost of sales (483.4 ) (1,729.0 ) (184.9 ) (1,038.0 ) 419.8 (3,015.5 ) Operating expenses (168.5 ) (96.6 ) (52.1 ) (81.3 ) — (398.5 ) Loss on derivative activity — — — — (11.1 ) (11.1 ) Segment profit (loss) $ 416.4 $ 175.9 $ 200.0 $ 57.2 $ (11.1 ) $ 838.4 Depreciation and amortization $ (196.9 ) $ (114.8 ) $ (140.6 ) $ (42.4 ) $ (9.2 ) $ (503.9 ) Impairments $ (473.1 ) $ — $ — $ (93.2 ) $ — $ (566.3 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 217.9 $ 79.1 $ 295.7 $ 74.3 $ 9.1 $ 676.1 Total assets $ 3,142.6 $ 2,349.3 $ 2,524.5 $ 836.8 $ 300.2 $ 9,153.4 The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Year Ended December 31, 2018 2017 2016 Segment profit $ 1,237.6 $ 959.4 $ 838.4 General and administrative expenses (130.2 ) (123.5 ) (119.3 ) Depreciation and amortization (577.3 ) (545.3 ) (503.9 ) Loss on disposition of assets (0.4 ) — (13.2 ) Impairments (365.8 ) (17.1 ) (566.3 ) Gain on litigation settlement — 26.0 — Operating income (loss) $ 163.9 $ 299.5 $ (364.3 )

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
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 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 $ 60.1 $ 98.9 $ 43.2 $ (230.2 ) $ (28.0 ) General partner interest in net income $ 10.6 $ 11.2 $ 7.7 $ 9.1 $ 38.6 Limited partners' interest in net income (loss) attributable to ENLK $ 21.6 $ 58.9 $ 5.2 $ (266.5 ) $ (180.8 ) Net income (loss) attributable to ENLK per limited partners’ unit: Basic common unit $ 0.06 $ 0.17 $ 0.01 $ (0.75 ) $ (0.51 ) Diluted common unit $ 0.06 $ 0.17 $ 0.01 $ (0.75 ) $ (0.51 ) 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 $ 18.1 $ 29.6 $ 25.5 $ 75.7 $ 148.9 General partner interest in net income $ 5.9 $ 10.8 $ 10.6 $ 11.0 $ 38.3 Limited partners' interest in net income (loss) attributable to ENLK $ (9.3 ) $ (0.5 ) $ (8.6 ) $ 36.3 $ 17.9 Net income (loss) attributable to ENLK per limited partners’ unit: Basic common unit $ (0.03 ) $ — $ (0.02 ) $ 0.10 $ 0.05 Diluted common unit $ (0.03 ) $ — $ (0.02 ) $ 0.10 $ 0.05 2016 Revenues $ 889.7 $ 1,033.2 $ 1,104.6 $ 1,224.9 $ 4,252.4 Impairments $ 566.3 $ — $ — $ — $ 566.3 Operating income (loss) $ (515.9 ) $ 46.4 $ 66.9 $ 38.3 $ (364.3 ) Net income (loss) attributable to ENLK $ (560.4 ) $ 5.0 $ 18.8 $ (28.6 ) $ (565.2 ) General partner interest in net income $ 7.4 $ 10.6 $ 10.8 $ 10.7 $ 39.5 Limited partners' interest in net loss attributable to ENLK $ (567.2 ) $ (23.5 ) $ (11.4 ) $ (60.0 ) $ (662.1 ) Net loss attributable to ENLK per limited partners’ unit: Basic common unit $ (1.74 ) $ (0.07 ) $ (0.03 ) $ (0.18 ) $ (1.99 ) Diluted common unit $ (1.74 ) $ (0.07 ) $ (0.03 ) $ (0.18 ) $ (1.99 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2018
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, non-cash investing activities, and non-cash financing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2018 2017 2016 Cash paid for interest $ 182.6 $ 163.8 $ 132.5 Cash paid for income taxes $ 1.5 $ 4.8 $ 2.8 Non-cash investing activities: Non-cash accrual of property and equipment $ 6.8 $ (22.7 ) $ 13.1 Discounted secured term loan receivable from contract restructuring $ 47.7 $ — $ — Non-cash financing activities: Installment payable, net of discount of $79.1 million (1) $ — $ — $ 420.9 Contribution from ENLC (2) $ — $ — $ 237.1 ___________________________ (1) We incurred installment purchase obligations, net of discount, payable to the seller in connection with the EOGP assets. We paid the second and final installments during January 2017 and 2018, respectively. See “ Note 3—Acquisition ” for further discussion. (2) Contribution from ENLC in connection with the acquisition of the EOGP assets. See “ Note 3—Acquisition ” for further discussion.

Other Information

Other Information	12 Months Ended
	Dec. 31, 2018
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, 2018 December 31, 2017 Natural gas and NGLs inventory $ 41.3 $ 30.1 Secured term loan receivable from contract restructuring, net of discount of $1.1 19.4 — Prepaid expenses and other 12.1 9.6 Natural gas and NGLs inventory, prepaid expenses, and other $ 72.8 $ 39.7 Other Current Liabilities: December 31, 2018 December 31, 2017 Accrued interest $ 37.3 $ 35.4 Accrued wages and benefits, including taxes 37.2 30.4 Accrued ad valorem taxes 28.1 27.8 Capital expenditure accruals 50.6 48.8 Onerous performance obligations 9.0 15.2 Other 84.5 64.8 Other current liabilities $ 246.7 $ 222.4

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	(18) Subsequent Events The Merger On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC , and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. As a result of the Merger: • Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) has been converted into the right to receive 1.15 ENLC common units. • Our general partner’s incentive distribution rights in ENLK have been eliminated. • The Series B Preferred Units will continue to be issued and outstanding following the Merger, except that certain terms of the Series B Preferred Units have been 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. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled. • The Series C Preferred Units and all of ENLK’s senior notes continue to be issued and outstanding following the Merger. • 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. • ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. Consolidated Credit Facility We refinanced our existing revolving credit facilities at ENLK and ENLC. As of December 31, 2018, we had a $1.5 billion facility at ENLK and a $250.0 million facility at ENLC. Following the Merger, we have combined these credit facilities into one $1.75 billion credit facility at ENLC, with respect to which ENLK is a guarantor. On December 11, 2018, ENLC entered into the Consolidated Credit Facility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. At the closing of the Merger, ENLK became a guarantor under the Consolidated Credit Facility. The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility includes procedures 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 2.50 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 5.00 to 1.00 . If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.125% to 2.00% ) or the Base Rate (the highest of the Federal Funds Rate plus 0.50% , the 30 -day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00% ). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately. At December 31, 2018 , ENLC was in compliance with and expects to be in compliance with the covenants in the Consolidated Credit Facility for at least the next twelve months. 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. EOGP is now a wholly-owned subsidiary of the Operating Partnership. Reporting Segments Effective January 1, 2019, we will report financial performance in four operating segments: Oklahoma, Permian, Louisiana and North Texas. Crude and Condensate operations will be combined regionally with natural gas and NGL operations in Oklahoma and Permian, and ORV operations will be included in the Louisiana segment.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	The accompanying consolidated financial statements have been prepared in accordance with GAAP for complete financial statements.
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	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—P roduct 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 replaces 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. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions): Increase (Decrease) in Revenue Due to Year Ended December 31, 2018 Product sales $ (235 ) Product sales—related parties (52 ) Midstream services (357 ) Midstream services—related parties (27 ) Total $ (671 ) 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 gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) 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 expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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. 2019 $ 252.1 2020 247.9 2021 104.5 2022 95.0 2023 92.9 Thereafter 281.9 Total $ 1,074.3 In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected $135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a $19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us $58.0 million in principal payments in various installments ending in May 2023, with interest accruing on the loan balance at 8.0% per annum beginning in 2020; and (iii) the counterparty granted to us a 1.0% term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized $45.5 million of midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer . 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 year ended December 31, 2018 . As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the year ended December 31, 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.
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 $12.4 million and $7.3 million at December 31, 2018 and 2017 , respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $10.4 million and $5.8 million at December 31, 2018 and 2017 , 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	We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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.
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 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 are as follows (in millions): Year Ended December 31, 2018 2017 Transmission assets $ 1,329.4 $ 1,338.7 Gathering systems 4,410.5 4,040.9 Gas processing plants 3,590.5 3,401.8 Other property and equipment 171.7 157.8 Construction in process 312.0 180.8 Property and equipment 9,814.1 9,120.0 Accumulated depreciation (2,967.4 ) (2,533.0 ) Property and equipment, net of accumulated depreciation $ 6,846.7 $ 6,587.0 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 $453.8 million , $418.2 million , and $386.9 million was recorded for the years ended December 31, 2018 , 2017 , and 2016 , 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, 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 expected 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 . For the year ended December 31, 2016 , we retired or sold net property and equipment of $106.6 million , which was offset by $0.3 million of insurance settlements and $93.1 million of proceeds from the sale of property, resulting in a loss on disposition of assets of $13.2 million . The loss on disposition of assets primarily related to the sale of the NPTL, a 140 -mile natural gas transportation pipeline in North Texas, that resulted in net proceeds of $84.6 million and a loss on sale of $13.4 million . 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) is composed of net income (loss), which consists of 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 the year ended December 31, 2018 and 2017, we reclassified an immaterial amount of losses from accumulated other comprehensive income (loss) to earnings. For additional information, see “ Note 11—Derivatives .”
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. For additional information, see “ Note 9—Investment in Unconsolidated Affiliates .”
Non-controlling Interests	(k) 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 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.
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.
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 Long-Term Liabilities	Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the Business Combination of $9.0 million and $26.9 million as of December 31, 2018 and 2017 , respectively. We have one delivery contract that requires us to deliver a specified volume of gas each month at an indexed base price with a term to mid-2019. We realize a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was based on forecasted discounted cash obligations in excess of market under this gas delivery contract in March 2014. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchased gas costs.
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, Derivatives and Hedging (“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. Prior to 2017, we did not designate interest rate swaps as hedges and, therefore, included the associated settlement gains and losses as interest expense on the consolidated statements of operations. In May 2017, we entered into an interest rate swap in connection with the issuance of our 2047 Notes. In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. For additional information, see “
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. In addition, we continually monitor and review the credit exposure of our marketing counter-parties, and letters of credit or other appropriate security are obtained 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. We had a reserve for uncollectible receivables of $0.3 million and $0.3 million as of December 31, 2018 and 2017 , respectively.
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
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”). We and ENLC each have similar unit-based payment plans for employees. 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 us. For additional information, see “ Note 10—Employee Incentive Plans .”
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. For additional information, see “ Note 13—Commitments and Contingencies .”
Debt Issuance Costs	Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense 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 $24.3 million and $25.9 million as of December 31, 2018 and 2017 , 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. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the related debt issuance.
Legal Costs Expected to be Incurred in Connection with a Loss Contingency	Legal costs incurred in connection with a loss contingency are expensed as incurred.
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	(x) Adopted Accounting Standards Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces 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. For additional information about our application of ASC 606 refer to “(c) Revenue Recognition” above. (y) Accounting Standards to be Adopted in Future Periods In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) — Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. We will adopt ASC 842 effective January 1, 2019. We have assessed the impact of adopting ASC 842 and implemented a lease accounting software. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. We are electing to apply certain practical expedients that are 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. We believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by approximately $75 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases . Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842)—Targeted Improvements (“ASU 2018-11”). ASU 2018-11 amends ASC 842 and allows entities to adopt the new leases standard using a modified retrospective approach. Under this new transition method, entities initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with current GAAP. We plan to utilize the optional transition method provided in ASU 2018-11 in conjunction with our adoption of ASC 842 in January 2019.

Significant Accounting Polici_3

Significant Accounting Policies Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	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. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions): Increase (Decrease) in Revenue Due to Year Ended December 31, 2018 Product sales $ (235 ) Product sales—related parties (52 ) Midstream services (357 ) Midstream services—related parties (27 ) Total $ (671 )
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table summarizes the expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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. 2019 $ 252.1 2020 247.9 2021 104.5 2022 95.0 2023 92.9 Thereafter 281.9 Total $ 1,074.3
Property, Plant and Equipment	The components of property and equipment are as follows (in millions): Year Ended December 31, 2018 2017 Transmission assets $ 1,329.4 $ 1,338.7 Gathering systems 4,410.5 4,040.9 Gas processing plants 3,590.5 3,401.8 Other property and equipment 171.7 157.8 Construction in process 312.0 180.8 Property and equipment 9,814.1 9,120.0 Accumulated depreciation (2,967.4 ) (2,533.0 ) Property and equipment, net of accumulated depreciation $ 6,846.7 $ 6,587.0 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, 2018 2017 2016 Devon 10.4 % 14.4 % 18.5 % Dow Hydrocarbons and Resources LLC 11.1 % 11.2 % 10.8 % Marathon Petroleum Corporation 11.5 % (1) (1) (1) Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the years ended December 31, 2017 and 2016 .

Acquisition (Tables)

Acquisition (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Schedule of Consideration and Fair Value of Identified Assets Received and Liabilities Assumed	The following table presents the considerations ENLK and ENLC paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration: Cash $ 783.6 Total installment payable, net of discount of $79.1 million 420.9 Contribution from ENLC 237.1 Total consideration $ 1,441.6 Purchase Price Allocation: Assets acquired: Current assets (including $12.8 million in cash) $ 23.0 Property and equipment 406.1 Intangibles 1,051.3 Liabilities assumed: Current liabilities (38.8 ) Total identifiable net assets $ 1,441.6

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The table below provides a summary of our change in carrying amount of goodwill (in millions) for the year ended December 31, 2018, by assigned reporting unit. For the year ended December 31, 2017, there were no changes to the carrying amounts of goodwill. Texas Oklahoma Totals Year Ended December 31, 2018 Balance, beginning of period $ 232.0 $ 190.3 $ 422.3 Impairment (232.0 ) — (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, 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 Year Ended December 31, 2016 Customer relationships, beginning of period $ 744.5 $ (54.6 ) $ 689.9 Acquisitions 1,051.3 — 1,051.3 Amortization expense — (117.0 ) (117.0 ) Customer relationships, end of period $ 1,795.8 $ (171.6 ) $ 1,624.2
Summary of Estimated Aggregate Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2019 $ 123.7 2020 123.7 2021 123.7 2022 123.7 2023 123.6 Thereafter 755.2 Total $ 1,373.6

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	Issuance Maturity Date of Notes Early Redemption Date Basis Point Premium 2019 Notes April 1, 2019 Prior to March 1, 2019 20 Basis Points 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 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 As of December 31, 2018 and 2017 , long-term debt consisted of the following (in millions): December 31, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt 2.70% Senior unsecured notes due 2019 (1) $ 400.0 $ — $ 400.0 $ 400.0 $ (0.1 ) $ 399.9 Term Loan due 2021 (2) 850.0 — 850.0 — — — 4.40% Senior unsecured notes due 2024 550.0 1.8 551.8 550.0 2.2 552.2 4.15% Senior unsecured notes due 2025 750.0 (0.9 ) 749.1 750.0 (1.0 ) 749.0 4.85% Senior unsecured notes due 2026 500.0 (0.5 ) 499.5 500.0 (0.6 ) 499.4 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 (6.2 ) 443.8 450.0 (6.5 ) 443.5 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 500.0 (0.1 ) 499.9 Debt classified as long-term $ 4,350.0 $ (6.1 ) 4,343.9 $ 3,500.0 $ (6.3 ) 3,493.7 Debt issuance cost (3) (24.3 ) (25.9 ) Less: Current maturities of long-term debt (1) (399.8 ) — Long-term debt, net of unamortized issuance cost $ 3,919.8 $ 3,467.8 (1) The 2.70% senior unsecured notes mature 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 . (2) 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 . (3) Net of amortization of $15.3 million and $12.0 million at December 31, 2018 and 2017 , respectively.
Schedule of Maturities of Long-term Debt	Maturities for the long-term debt as of December 31, 2018 are as follows (in millions): 2019 $ 400.0 2020 — 2021 850.0 2022 — 2023 — Thereafter 3,100.0 Subtotal 4,350.0 Less: net discount (6.1 ) Less: debt issuance cost (24.3 ) Less: current maturities of long-term debt (399.8 ) Long-term debt, net of unamortized issuance cost $ 3,919.8

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax provision (benefit) are as follows (in millions): Year Ended December 31, 2018 2017 2016 Current income tax provision $ 1.8 $ 2.6 $ 1.9 Deferred tax benefit (3.9 ) (26.6 ) (0.6 ) Total income tax provision (benefit) $ (2.1 ) $ (24.0 ) $ 1.3

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 , and 2016 is provided below: Declaration period Distribution Cash distribution Date paid/payable 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 2016 First Quarter of 2016 992,445 $ — May 12, 2016 Second Quarter of 2016 1,083,589 $ — August 11, 2016 Third Quarter of 2016 1,106,616 $ — November 10, 2016 Fourth Quarter of 2016 1,130,131 $ — February 13, 2017 A summary of the distribution activity relating to the common units for the years ended December 31, 2018 , 2017 , and 2016 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 2016 First Quarter of 2016 $ 0.390 May 12, 2016 Second Quarter of 2016 $ 0.390 August 11, 2016 Third Quarter of 2016 $ 0.390 November 11, 2016 Fourth Quarter of 2016 $ 0.390 February 13, 2017
Computation of Basic and Diluted Earnings per Limited Partner Units	The following table reflects the computation of basic and diluted earnings per limited partner unit for the periods presented (in millions, except per unit amounts): Year Ended December 31, 2018 2017 2016 Distributed earnings allocated to: Common units (1) $ 548.1 $ 541.2 $ 520.0 Unvested restricted units (1) 4.4 4.0 3.5 Total distributed earnings $ 552.5 $ 545.2 $ 523.5 Undistributed loss allocated to: Common units $ (727.5 ) $ (523.5 ) $ (1,177.6 ) Unvested restricted units (5.8 ) (3.8 ) (8.0 ) Total undistributed loss $ (733.3 ) $ (527.3 ) $ (1,185.6 ) Net income (loss) allocated to: Common units $ (179.4 ) $ 17.7 $ (657.6 ) Unvested restricted units (1.4 ) 0.2 (4.5 ) Total limited partners’ interest in net income (loss) $ (180.8 ) $ 17.9 $ (662.1 ) Basic and diluted net income (loss) per unit: Basic $ (0.51 ) $ 0.05 $ (1.99 ) Diluted $ (0.51 ) $ 0.05 $ (1.99 ) ___________________________ (1) Represents distribution activity consistent with the distribution activity table in section “(e) Common Unit Distributions” above.
Schedule of Unit Amounts Used to Compute Basic and Diluted Earnings per Limited Partner Unit	The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the years ended December 31, 2018 , 2017 , and 2016 (in millions): Year Ended December 31, 2018 2017 2016 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) 351.3 346.9 333.3 Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) 351.3 346.9 333.3 Dilutive effect of non-vested restricted units (2) — 1.4 — Total weighted average limited partner diluted common units outstanding 351.3 348.3 333.3 ___________________________ (1) Weighted average limited partner basic common units outstanding for the years ended December 31, 2016 included the weighted average impact of 2,740,273 Class C Units, which converted into common units on May 13, 2016. (2) All common unit equivalents were antidilutive for the years ended December 31, 2018 and 2016 because the limited partners were allocated a net loss.
Incentive Distributions	The net income (loss) allocated to the general partner is as follows (in millions): Year Ended December 31, 2018 2017 2016 Income allocation for incentive distributions $ 59.5 $ 58.9 $ 56.8 Unit-based compensation attributable to ENLC’s restricted units (20.3 ) (21.0 ) (14.7 ) General partner share of net income (loss) (0.6 ) 0.4 (2.6 ) General partner interest in net income $ 38.6 $ 38.3 $ 39.5

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 GCF Distributions $ 22.3 $ 12.7 $ 7.5 Equity in income $ 15.8 $ 12.6 $ 3.4 HEP Contributions (1) $ — $ — $ 45.0 Distributions (2) $ — $ — $ 50.2 Equity in income (loss) (3) $ — $ (3.4 ) $ (23.3 ) Cedar Cove JV Contributions $ 0.1 $ 12.6 $ 28.8 Distributions $ 0.4 $ 0.8 $ — Equity in income $ (2.5 ) $ 0.4 $ — Total Contributions (1) $ 0.1 $ 12.6 $ 73.8 Distributions (2) $ 22.7 $ 13.5 $ 57.7 Equity in income (loss) (3) $ 13.3 $ 9.6 $ (19.9 ) ___________________________ (1) Contributions for the year ended December 31, 2016 included $32.7 million of contributions to HEP for preferred units issued by HEP. These preferred units were redeemed during the third quarter 2016. (2) Distributions for the year ended December 31, 2016 included a redemption of $32.7 million of preferred units issued by HEP. (3) Included losses of $3.4 million and $20.1 million for the years ended December 31, 2017 and 2016 , respectively, related to the sale of our HEP interests. The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2018 and 2017 (in millions): December 31, 2018 December 31, 2017 GCF $ 41.9 $ 48.4 Cedar Cove JV 38.2 41.0 Total investments in unconsolidated affiliates $ 80.1 $ 89.4

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [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, 2018 2017 2016 Cost of unit-based compensation charged to general and administrative expense $ 30.0 $ 37.1 $ 23.4 Cost of unit-based compensation charged to operating expense 10.8 10.7 6.6 Total unit-based compensation expense $ 40.8 $ 47.8 $ 30.0
Summary of Restricted Incentive Unit Activity	ENLK restricted incentive units are 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, 2018 is provided below: Year Ended December 31, 2018 EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,980,224 $ 15.81 Granted (1) 1,590,100 15.27 Vested (1)(2) (835,115 ) 19.68 Forfeited (178,939 ) 12.75 Non-vested, end of period 2,556,270 $ 14.43 Aggregate intrinsic value, end of period (in millions) $ 28.1 ___________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2018, our general partner granted 200,753 restricted incentive units with a fair value of $3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units include 261,063 units withheld for payroll taxes paid on behalf of employees. 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, 2018 is provided below: Year Ended December 31, 2018 EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,889,310 $ 16.33 Granted (1) 1,473,195 15.76 Vested (1)(2) (769,848 ) 21.40 Forfeited (166,790 ) 12.74 Non-vested, end of period 2,425,867 $ 14.62 Aggregate intrinsic value, end of period (in millions) $ 23.0 ___________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted 194,185 restricted incentive units with a fair value of $3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units include 244,123 units withheld for payroll taxes paid on behalf of employees.
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) during the years ended December 31, 2018 , 2017 , and 2016 is provided below (in millions): Year Ended December 31, EnLink Midstream, LLC Restricted Incentive Units: 2018 2017 2016 Aggregate intrinsic value of units vested $ 12.8 $ 15.3 $ 4.1 Fair value of units vested $ 16.5 $ 22.2 $ 12.4 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, 2018 , 2017 , and 2016 is provided below (in millions): Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2018 2017 2016 Aggregate intrinsic value of units vested $ 13.1 $ 16.6 $ 4.1 Fair value of units vested $ 16.4 $ 22.6 $ 9.5
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value of performance units granted and the related assumptions by performance unit grant date: EnLink Midstream Partners, LP Performance Units: March 2018 March 2017 October 2016 February 2016 January 2016 TSR price $15.44 $17.55 $17.71 $14.82 $14.82 Risk-free interest rate 2.38 % 1.62 % 0.91 % 0.89 % 1.10 % Volatility factor 43.85 % 43.94 % 44.62 % 42.33 % 39.71 % Distribution yield 10.50 % 8.70 % 8.80 % 19.20 % 12.10 % The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream, LLC Performance Units: March 2018 March 2017 October 2016 February 2016 January 2016 TSR price $ 16.55 $ 18.29 $ 16.75 $ 15.38 $ 15.38 Risk-free interest rate 2.38 % 1.62 % 0.91 % 0.89 % 1.10 % Volatility factor 51.36 % 52.07 % 52.89 % 52.05 % 46.02 % Distribution yield 6.70 % 5.40 % 6.10 % 14.00 % 8.60 %
Summary of Performance Units	The following table presents a summary of the performance units: Year Ended December 31, 2018 EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 548,839 $ 22.14 Granted 223,865 21.63 Vested (1) (283,637 ) 27.25 Forfeited (70,918 ) 17.75 Non-vested, end of period 418,149 $ 19.15 Aggregate intrinsic value, end of period (in millions) $ 4.0 (1) Vested units included 100,109 units withheld for payroll taxes paid on behalf of employees and 109,819 units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes. 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 year ended December 31, 2018 is provided below (in millions). No performance units vested for the years ended 2017 and 2016 . EnLink Midstream, LLC Performance Units: Year Ended December 31, 2018 Aggregate intrinsic value of units vested $ 4.7 Fair value of units vested $ 7.7 The following table presents a summary of the performance units: Year Ended December 31, 2018 EnLink Midstream Partners, LP Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 585,285 $ 20.52 Granted 256,345 19.24 Vested (1) (313,610 ) 24.43 Forfeited (76,351 ) 16.62 Non-vested, end of period 451,669 $ 17.74 Aggregate intrinsic value, end of period (in millions) $ 5.0 (1) Vested units included 112,101 units withheld for payroll taxes paid on behalf of employees and 120,250 units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes. 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 year ended December 31, 2018 is provided below (in millions). No performance units vested for the years ended 2017 and 2016 . EnLink Midstream Partners, LP Performance Units: Year Ended December 31, 2018 Aggregate intrinsic value of units vested $ 5.0 Fair value of units vested $ 7.7

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
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, 2018 2017 2016 Change in fair value of derivatives $ 10.1 $ 4.7 $ (20.1 ) Realized gain (loss) on derivatives (4.9 ) (8.9 ) 9.0 Gain (loss) on derivative activity $ 5.2 $ (4.2 ) $ (11.1 )
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, 2018 December 31, 2017 Fair value of derivative assets — current $ 28.6 $ 6.8 Fair value of derivative assets — long-term 4.1 — Fair value of derivative liabilities — current (21.8 ) (8.4 ) Fair value of derivative liabilities — long-term (2.4 ) — Net fair value of derivatives $ 8.5 $ (1.6 )
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, 2018 (in millions). The remaining term of the contracts extend no later than December 2022. December 31, 2018 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (29.0 ) $ 4.5 NGL (long contracts) Swaps Gallons 7.7 0.1 Natural Gas (short contracts) Swaps MMBtu (9.0 ) (1.6 ) Natural Gas (long contracts) Swaps MMBtu 14.9 (1.5 ) Crude and Condensate (short contracts) Swaps MMbbls (12.9 ) 23.6 Crude and Condensate (long contracts) Swaps MMbbls 1.0 (16.6 ) Total fair value of derivatives $ 8.5

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2018 December 31, 2017 Commodity Swaps (1) $ 8.5 $ (1.6 ) ___________________________ (1) The fair values of derivative contracts included in assets or liabilities for risk management activities 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, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value Long-term debt, including current maturities of long-term debt (1) $ 4,319.6 $ 3,953.6 $ 3,467.8 $ 3,575.6 Installment Payables $ — $ — $ 249.5 $ 249.6 Obligations under capital lease $ 2.5 $ 2.2 $ 4.1 $ 3.4 Secured term loan receivable $ 51.1 $ 51.1 $ — $ — ___________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of $24.3 million and $25.9 million at December 31, 2018 and 2017 , respectively. The respective fair values do not factor in debt issuance costs.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The following table summarizes our remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions): 2019 $ 14.1 2020 10.3 2021 8.7 2022 8.6 2023 8.8 Thereafter 49.8 Total $ 100.3

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Summarized Financial Information	Summarized financial information for our reportable segments is shown in the following tables (in millions): Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2018 Natural gas sales $ 292.9 $ 531.1 $ 189.7 $ — $ — $ 1,013.7 NGL sales 28.6 2,786.3 25.2 0.9 — 2,841.0 Crude oil and condensate sales — 0.5 0.7 2,656.4 — 2,657.6 Product sales 321.5 3,317.9 215.6 2,657.3 — 6,512.3 Natural gas sales—related parties — — 2.5 — — 2.5 NGL sales—related parties 503.5 47.4 590.8 — (1,104.3 ) 37.4 Crude oil and condensate sales—related parties 49.3 0.3 85.6 3.3 (137.4 ) 1.1 Product sales—related parties 552.8 47.7 678.9 3.3 (1,241.7 ) 41.0 Gathering and transportation 177.9 68.8 149.1 3.1 — 398.9 Processing 101.0 3.3 122.8 — — 227.1 NGL services — 59.6 — — — 59.6 Crude services — — 0.6 66.5 — 67.1 Other services 9.6 0.6 0.2 0.2 — 10.6 Midstream services 288.5 132.3 272.7 69.8 — 763.3 Gathering and transportation—related parties 122.7 — 80.6 — — 203.3 Processing—related parties 108.6 — 48.4 — — 157.0 NGL services—related parties — 3.3 — — (3.3 ) — Crude services—related parties — — 1.5 14.9 — 16.4 Other services—related parties 0.5 — — — — 0.5 Midstream services—related parties 231.8 3.3 130.5 14.9 (3.3 ) 377.2 Revenue from contracts with customers 1,394.6 3,501.2 1,297.7 2,745.3 (1,245.0 ) 7,693.8 Cost of sales (753.9 ) (3,158.7 ) (744.0 ) (2,596.4 ) 1,245.0 (6,008.0 ) Operating expenses (180.6 ) (108.3 ) (89.2 ) (75.3 ) — (453.4 ) Gain on derivative activity — — — — 5.2 5.2 Segment profit $ 460.1 $ 234.2 $ 464.5 $ 73.6 $ 5.2 $ 1,237.6 Depreciation and amortization $ (216.2 ) $ (122.7 ) $ (178.1 ) $ (51.6 ) $ (8.7 ) $ (577.3 ) Impairments $ (232.0 ) $ (24.6 ) $ — $ (109.2 ) $ — $ (365.8 ) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 249.4 $ 47.0 $ 412.5 $ 135.7 $ 5.3 $ 849.9 Total assets $ 2,925.3 $ 2,347.9 $ 3,116.5 $ 959.3 $ 222.3 $ 9,571.3 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2017 Product sales $ 325.0 $ 2,529.6 $ 128.8 $ 1,375.0 $ — $ 4,358.4 Product sales—related parties 500.3 45.0 349.4 0.8 (750.6 ) 144.9 Midstream services 116.3 220.6 155.0 60.4 — 552.3 Midstream services—related parties 424.3 136.4 241.6 17.4 (131.5 ) 688.2 Cost of sales (772.3 ) (2,618.1 ) (522.9 ) (1,330.3 ) 882.1 (4,361.5 ) Operating expenses (172.7 ) (101.3 ) (64.6 ) (80.1 ) — (418.7 ) Loss on derivative activity — — — — (4.2 ) (4.2 ) Segment profit (loss) $ 420.9 $ 212.2 $ 287.3 $ 43.2 $ (4.2 ) $ 959.4 Depreciation and amortization $ (215.2 ) $ (116.1 ) $ (156.6 ) $ (47.5 ) $ (9.9 ) $ (545.3 ) Impairments $ — $ (0.8 ) $ — $ (16.3 ) $ — $ (17.1 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 145.4 $ 75.1 $ 442.1 $ 79.1 $ 26.4 $ 768.1 Total assets $ 3,094.8 $ 2,408.5 $ 2,836.7 $ 929.5 $ 144.5 $ 9,414.0 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Year Ended December 31, 2016 Product sales $ 237.2 $ 1,632.5 $ 48.5 $ 1,090.7 $ — $ 3,008.9 Product sales—related parties 287.6 57.8 120.4 1.5 (333.0 ) 134.3 Midstream services 104.2 215.4 82.2 65.4 — 467.2 Midstream services—related parties 439.3 95.8 185.9 18.9 (86.8 ) 653.1 Cost of sales (483.4 ) (1,729.0 ) (184.9 ) (1,038.0 ) 419.8 (3,015.5 ) Operating expenses (168.5 ) (96.6 ) (52.1 ) (81.3 ) — (398.5 ) Loss on derivative activity — — — — (11.1 ) (11.1 ) Segment profit (loss) $ 416.4 $ 175.9 $ 200.0 $ 57.2 $ (11.1 ) $ 838.4 Depreciation and amortization $ (196.9 ) $ (114.8 ) $ (140.6 ) $ (42.4 ) $ (9.2 ) $ (503.9 ) Impairments $ (473.1 ) $ — $ — $ (93.2 ) $ — $ (566.3 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 217.9 $ 79.1 $ 295.7 $ 74.3 $ 9.1 $ 676.1 Total assets $ 3,142.6 $ 2,349.3 $ 2,524.5 $ 836.8 $ 300.2 $ 9,153.4
Reconciliation of Profits Reported to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Year Ended December 31, 2018 2017 2016 Segment profit $ 1,237.6 $ 959.4 $ 838.4 General and administrative expenses (130.2 ) (123.5 ) (119.3 ) Depreciation and amortization (577.3 ) (545.3 ) (503.9 ) Loss on disposition of assets (0.4 ) — (13.2 ) Impairments (365.8 ) (17.1 ) (566.3 ) Gain on litigation settlement — 26.0 — Operating income (loss) $ 163.9 $ 299.5 $ (364.3 )

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2018
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 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 $ 60.1 $ 98.9 $ 43.2 $ (230.2 ) $ (28.0 ) General partner interest in net income $ 10.6 $ 11.2 $ 7.7 $ 9.1 $ 38.6 Limited partners' interest in net income (loss) attributable to ENLK $ 21.6 $ 58.9 $ 5.2 $ (266.5 ) $ (180.8 ) Net income (loss) attributable to ENLK per limited partners’ unit: Basic common unit $ 0.06 $ 0.17 $ 0.01 $ (0.75 ) $ (0.51 ) Diluted common unit $ 0.06 $ 0.17 $ 0.01 $ (0.75 ) $ (0.51 ) 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 $ 18.1 $ 29.6 $ 25.5 $ 75.7 $ 148.9 General partner interest in net income $ 5.9 $ 10.8 $ 10.6 $ 11.0 $ 38.3 Limited partners' interest in net income (loss) attributable to ENLK $ (9.3 ) $ (0.5 ) $ (8.6 ) $ 36.3 $ 17.9 Net income (loss) attributable to ENLK per limited partners’ unit: Basic common unit $ (0.03 ) $ — $ (0.02 ) $ 0.10 $ 0.05 Diluted common unit $ (0.03 ) $ — $ (0.02 ) $ 0.10 $ 0.05 2016 Revenues $ 889.7 $ 1,033.2 $ 1,104.6 $ 1,224.9 $ 4,252.4 Impairments $ 566.3 $ — $ — $ — $ 566.3 Operating income (loss) $ (515.9 ) $ 46.4 $ 66.9 $ 38.3 $ (364.3 ) Net income (loss) attributable to ENLK $ (560.4 ) $ 5.0 $ 18.8 $ (28.6 ) $ (565.2 ) General partner interest in net income $ 7.4 $ 10.6 $ 10.8 $ 10.7 $ 39.5 Limited partners' interest in net loss attributable to ENLK $ (567.2 ) $ (23.5 ) $ (11.4 ) $ (60.0 ) $ (662.1 ) Net loss attributable to ENLK per limited partners’ unit: Basic common unit $ (1.74 ) $ (0.07 ) $ (0.03 ) $ (0.18 ) $ (1.99 ) Diluted common unit $ (1.74 ) $ (0.07 ) $ (0.03 ) $ (0.18 ) $ (1.99 )

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Summary of Non-Cash Financing Activities	The following schedule summarizes cash paid for interest and income taxes, non-cash investing activities, and non-cash financing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2018 2017 2016 Cash paid for interest $ 182.6 $ 163.8 $ 132.5 Cash paid for income taxes $ 1.5 $ 4.8 $ 2.8 Non-cash investing activities: Non-cash accrual of property and equipment $ 6.8 $ (22.7 ) $ 13.1 Discounted secured term loan receivable from contract restructuring $ 47.7 $ — $ — Non-cash financing activities: Installment payable, net of discount of $79.1 million (1) $ — $ — $ 420.9 Contribution from ENLC (2) $ — $ — $ 237.1 ___________________________ (1) We incurred installment purchase obligations, net of discount, payable to the seller in connection with the EOGP assets. We paid the second and final installments during January 2017 and 2018, respectively. See “ Note 3—Acquisition ” for further discussion. (2) Contribution from ENLC in connection with the acquisition of the EOGP assets. See “ Note 3—Acquisition ” for further discussion.

Other Information (Tables)

Other Information (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 December 31, 2017 Natural gas and NGLs inventory $ 41.3 $ 30.1 Secured term loan receivable from contract restructuring, net of discount of $1.1 19.4 — Prepaid expenses and other 12.1 9.6 Natural gas and NGLs inventory, prepaid expenses, and other $ 72.8 $ 39.7 Other Current Liabilities: December 31, 2018 December 31, 2017 Accrued interest $ 37.3 $ 35.4 Accrued wages and benefits, including taxes 37.2 30.4 Accrued ad valorem taxes 28.1 27.8 Capital expenditure accruals 50.6 48.8 Onerous performance obligations 9.0 15.2 Other 84.5 64.8 Other current liabilities $ 246.7 $ 222.4

Organization and Summary of S_2

Organization and Summary of Significant Agreements (Details) mi in Thousands, bbl in Thousands	Jan. 31, 2019shares	Jul. 18, 2018	Dec. 31, 2018Bcf / dplantfractionatormibbl	Jan. 25, 2019	Jan. 07, 2016	Dec. 31, 2015	Mar. 07, 2014
Business Acquisition [Line Items]
Number of miles of pipeline | mi			11
Number of natural gas processing plants | plant			20
Amount of processing capacity | Bcf / d			4.9
Number of fractionators | fractionator			7
Capacity of fractionators per day, in barrels | bbl			280
EnLink Midstream Holdings, LP
Business Acquisition [Line Items]
Acquired voting interest							50.00%
EnLink Midstream Holdings, LP | ENLC
Business Acquisition [Line Items]
Acquired voting interest						50.00%
EOGP
Business Acquisition [Line Items]
Acquired voting interest					83.90%
EOGP | ENLC
Business Acquisition [Line Items]
Acquired voting interest					16.10%
Subsequent Event | EOGP | ENLC
Business Acquisition [Line Items]
Acquired voting interest				16.10%
TOMPC LLC and TOM-STACK, LLC | EOGP
Business Acquisition [Line Items]
Acquired voting interest					100.00%
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%
ENLC | GIP Stetson II
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests		63.80%
ENLC | Subsequent Event
Business Acquisition [Line Items]
Shares issued for transfer of ownership (in shares) | shares	55,827,221
EOGP | ENLC
Business Acquisition [Line Items]
Noncontrolling interest percentage			16.10%
EOGP | Subsequent Event | ENLC
Business Acquisition [Line Items]
Noncontrolling interest percentage	16.10%

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	May 31, 2018USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)contract	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)mi	Jan. 01, 2019USD ($)	May 31, 2017USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Decrease in revenue from contracts with customers			$ (7,693,800,000)
Long-term purchase commitment, expected gross operating margin	$ 135,100,000
Long-term purchase commitment, deficiency fee received	19,700,000
Financing receivable, gross	$ 58,000,000
Financing receivable, interest rate, stated percentage	8.00%
Overriding royalty interest percentage	1.00%
Long-term purchase commitment, contract restructuring income		$ 45,500,000
Gas imbalance payables			12,400,000	$ 7,300,000
Gas imbalance receivables			10,400,000	5,800,000
Depreciation			453,800,000	418,200,000	$ 386,900,000
Retired or sold net property, plant and equipment			2,100,000	8,400,000	106,600,000
Expected proceeds from insurance settlements				6,100,000
Proceeds from sale of productive assets			1,700,000	2,300,000	93,100,000
Gain (loss) on productive assets			(400,000)	0
Proceeds from insurance settlement					300,000
Loss on disposition of assets			400,000	0	13,200,000
Impairment charge on property, plant, and equipment				17,100,000
Provision for loss on contracts			$ 9,000,000	26,900,000
Number of contracts | contract			1
Accumulated other comprehensive loss			$ 2,100,000	2,100,000			$ 2,200,000
Allowance for bad debt			300,000	300,000
Environmental remediation expense			0	0	0
Debt issuance costs, noncurrent, net			$ 24,300,000	$ 25,900,000
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
North Texas Pipeline System
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Proceeds from sale of productive assets					84,600,000
Gain (loss) on productive assets					$ (13,400,000)
Number of miles of natural gas | mi					140
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%
Scenario, Forecast | Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset (less than)						$ 75,000,000
Lease liability (less than)						$ 70,000,000
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
EOGP | ENLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncontrolling interest percentage			16.10%
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%

Significant Accounting Polici_5

Significant Accounting Policies - Summary of Changes in Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	$ 7,693.8
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(671)
Product sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	6,512.3	$ 4,358.4	$ 3,008.9
Product sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(235)
Product sales—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	41	144.9	134.3
Product sales—related parties | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(52)
Midstream services
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	763.3	552.3	467.2
Midstream services | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(357)
Midstream services—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	377.2	$ 688.2	$ 653.1
Midstream services—related parties | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	$ (27)

Significant Accounting Polici_6

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 1,074.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 252.1
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]: 2020-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 247.9
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	$ 104.5
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	$ 95
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	$ 92.9
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	$ 281.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period

Significant Accounting Polici_7

Significant Accounting Policies - Components of Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property and equipment	$ 9,814.1	$ 9,120
Accumulated depreciation	(2,967.4)	(2,533)
Property and equipment, net of accumulated depreciation	6,846.7	6,587
Transmission assets
Property, Plant and Equipment [Line Items]
Property and equipment	$ 1,329.4	1,338.7
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	$ 4,410.5	4,040.9
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	$ 3,590.5	3,401.8
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	$ 171.7	157.8
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	$ 312	$ 180.8

Significant Accounting Polici_8

Significant Accounting Policies - Customer Concentration Risk (Details) - Sales Revenue, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Devon
Concentration Risk [Line Items]
Concentration risk	10.40%	14.40%	18.50%
Dow Hydrocarbons and Resources LLC
Concentration Risk [Line Items]
Concentration risk	11.10%	11.20%	10.80%
Marathon Petroleum Corporation
Concentration Risk [Line Items]
Concentration risk	11.50%

Acquisition - Narrative (Detail

Acquisition - Narrative (Details) - EOGP - USD ($) $ in Millions	Jan. 07, 2016	Jan. 31, 2018	Jan. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Acquired voting interest	83.90%
Recognized identifiable assets acquired and liabilities assumed, net	$ 1,441.6
First installment	1,020
Second installment			$ 250
Final installment		$ 250
Cash	$ 783.6
Estimated life of acquired intangible assets	15 years
Transaction costs				$ 3.7
Recognized revenue				246.1
Net gain (loss) related to assets acquired				(34.1)
Non-Controlling Interest
Business Acquisition [Line Items]
Net gain (loss) related to assets acquired				$ (5.5)
ENLC
Business Acquisition [Line Items]
Acquired voting interest	16.10%
Cash	$ 22.2
Common Units
Business Acquisition [Line Items]
Equity interest issued or issuable, number of shares (in shares)	15,564,009

Acquisition - Schedule of Consi

Acquisition - Schedule of Consideration, Assets and Liabilities (Details) - USD ($) $ in Millions	Jan. 07, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Consideration:
Contribution from ENLC				$ 1.5
EOGP
Consideration:
Cash	$ 783.6
Total installment payable, net of discount of $79.1 million	420.9	$ 0	$ 0	420.9
Installment payable discount	79.1			79.1
Total consideration	1,441.6
Assets acquired:
Current assets (including cash)	23
Cash acquired	12.8
Property and equipment	406.1
Intangibles	1,051.3
Liabilities assumed:
Current liabilities	(38.8)
Total identifiable net assets	1,441.6
ENLC
Consideration:
Contribution from ENLC				$ 237.1
ENLC | EOGP
Consideration:
Cash	22.2
Contribution from ENLC	$ 237.1

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Changes in Carrying Value of Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2016	Dec. 31, 2018
Goodwill [Roll Forward]
Balance, beginning of period			$ 422.3
Impairment	$ (232)	$ (566.3)	(232)
Balance, end of period	190.3		190.3
Operating Segments | Texas
Goodwill [Roll Forward]
Balance, beginning of period			232
Balance, end of period	0		0
Operating Segments | Oklahoma
Goodwill [Roll Forward]
Balance, beginning of period			190.3
Impairment			0
Balance, end of period	190.3		190.3
Operating Segments | Crude and Condensate
Goodwill [Roll Forward]
Balance, beginning of period			0
Balance, end of period	$ 0		$ 0

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill
Goodwill impairment loss	$ 232	$ 566.3	$ 232
Amortization expense			$ 123.5	$ 127.1	$ 117
Minimum
Goodwill
Amortization period			5 years
Maximum
Goodwill
Amortization period			20 years
Weighted average
Goodwill
Amortization period			15 years

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Finite-lived Intangible Assets [Roll Forward]
Accumulated amortization, beginning balance	$ (298.7)
Amortization expense	(123.5)	$ (127.1)	$ (117)
Accumulated amortization, ending balance	(422.2)	(298.7)
Net carrying amount, ending balance	1,373.6
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance	1,795.8	1,795.8	744.5
Accumulated amortization, beginning balance	(298.7)	(171.6)	(54.6)
Net carrying amount, beginning balance	1,497.1	1,624.2	689.9
Acquisitions			1,051.3
Amortization expense	(123.5)	(127.1)	(117)
Gross carrying amount, ending balance	1,795.8	1,795.8	1,795.8
Accumulated amortization, ending balance	(422.2)	(298.7)	(171.6)
Net carrying amount, ending balance	$ 1,373.6	$ 1,497.1	$ 1,624.2

Goodwill and Intangible Asset_5

Goodwill and Intangible Assets - Amortization Expense (Details) $ in Millions	Dec. 31, 2018USD ($)
Summary of estimated amortization expense
2,019	$ 123.7
2,020	123.7
2,021	123.7
2,022	123.7
2,023	123.6
Thereafter	755.2
Total	$ 1,373.6

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		Jul. 18, 2018	Sep. 09, 2016	Jan. 07, 2016	Jan. 01, 2014	Jan. 31, 2016	Jun. 30, 2014	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Jul. 18, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 25, 2019
Related Party Transaction
Accounts payable to related party								$ 4.3				$ 18.4									$ 4.3	$ 18.4
Revenues								2,058.3	$ 2,114.3	$ 1,764.7	$ 1,761.7	1,756.2	$ 1,397.9	$ 1,263.6	$ 1,321.9	$ 1,224.9	$ 1,104.6	$ 1,033.2	$ 889.7		7,699	5,739.6	$ 4,252.4
Cost of sales	[1]																				6,008	4,361.5	3,015.5
Cedar Cove Joint Venture
Related Party Transaction
Revenues																					0.5	5.4
Cost of sales																					44.1	30.6
Reimbursed Capital Expenditures
Related Party Transaction
Transactions with related party																					26.6	48.4	31.5
Tax Sharing Agreement
Related Party Transaction
Transactions with related party																				$ 0.4		1.2	2.3
EOGP
Related Party Transaction
Consideration transferred				$ 1,441.6
Acquired voting interest				83.90%
Devon
Related Party Transaction
Accounts receivable balance												102.7										102.7
Accounts payable to related party												16.3										16.3
Product sales																				321.3
Revenue from related parties																				66.6		78	107.2
Devon | Enlink Midstream Services Agreement
Related Party Transaction
Term of contract					10 years
Devon | S W G Pipeline Agreement
Related Party Transaction
Term of contract					10 years
Devon | Minimum Volume Contract
Related Party Transaction
Product sales																				50.8		81.9	46.2
Devon | EOGP
Related Party Transaction
Term of contract						15 years
Minimum volume commitment						4 years
Revenue from related parties																				77.6		100.4	34.4
Devon | VEX Pipeline
Related Party Transaction
Term of contract							5 years
Minimum volume commitment							5 years
Revenue from related parties																				3.5		17.8	18.7
Cedar Cove Joint Venture
Related Party Transaction
Accounts receivable balance								0.7				0									0.7	0
Accounts payable to related party								$ 4.3				$ 0									4.3	0
Term of contract			15 years
ENLC
Related Party Transaction
Reimbursement revenue																					$ 2.5	2.4	2.3
Acacia
Related Party Transaction
Revenue from related parties																				4.9		13.8	15.2
Gulf Coast Fractionators
Related Party Transaction
Revenue from related parties																				$ 10.5		$ 12.6	$ 3.4
Sales Revenue, Net | Customer Concentration Risk | Devon
Related Party Transaction
Concentration risk																					5.40%	14.40%	18.50%
ENLC | EOGP
Related Party Transaction
Acquired voting interest				16.10%
EnLink Midstream Partners, LP | Devon
Related Party Transaction
Product sales																						$ 615.5	$ 611.8
Devon | GIP
Related Party Transaction
Consideration transferred		$ 3,125
Devon | Gulf Coast Fractionators
Related Party Transaction
Ownership interest								38.75%													38.75%
Subsequent Event | ENLC | EOGP
Related Party Transaction
Acquired voting interest																								16.10%
[1]	Includes related party cost of sales of $114.1 million, $211.0 million, and $150.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($)	1 Months Ended
	Dec. 31, 2018	Dec. 11, 2018	Dec. 31, 2017	May 11, 2017	Jul. 14, 2016	May 12, 2015	Nov. 12, 2014	Mar. 19, 2014
Debt Instrument
Outstanding Principal	$ 4,350,000,000		$ 3,500,000,000
Premium (Discount)	(6,100,000)		(6,300,000)
Long-Term Debt	4,343,900,000		3,493,700,000
Less: debt issuance cost	(24,300,000)		(25,900,000)
Less: Current maturities of long-term debt	(399,800,000)		0
Long-term debt, net of unamortized issuance cost	3,919,800,000		3,467,800,000
Amortization	15,300,000		12,000,000
2.70% Senior unsecured notes due 2019
Debt Instrument
Outstanding Principal	400,000,000		400,000,000
Premium (Discount)	0		(100,000)
Long-Term Debt	$ 400,000,000		399,900,000
Stated interest rate	2.70%							2.70%
Debt instrument, face amount								$ 400,000,000
Term Loan due 2021
Debt Instrument
Outstanding Principal	$ 850,000,000		0
Premium (Discount)	0		0
Long-Term Debt	850,000,000		0
4.40% Senior unsecured notes due 2024
Debt Instrument
Outstanding Principal	550,000,000		550,000,000
Premium (Discount)	1,800,000		2,200,000
Long-Term Debt	$ 551,800,000		552,200,000
Stated interest rate	4.40%							4.40%
Debt instrument, face amount							$ 100,000,000	$ 450,000,000
4.15% Senior unsecured notes due 2025
Debt Instrument
Outstanding Principal	$ 750,000,000		750,000,000
Premium (Discount)	(900,000)		(1,000,000)
Long-Term Debt	$ 749,100,000		749,000,000
Stated interest rate	4.15%					4.15%
Debt instrument, face amount						$ 750,000,000
4.85% Senior unsecured notes due 2026
Debt Instrument
Outstanding Principal	$ 500,000,000		500,000,000
Premium (Discount)	(500,000)		(600,000)
Long-Term Debt	$ 499,500,000		499,400,000
Stated interest rate	4.85%				4.85%
Debt instrument, face amount					$ 500,000,000
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
Stated interest rate	5.60%							5.60%
Debt instrument, face amount								$ 350,000,000
5.05% Senior unsecured notes due 2045
Debt Instrument
Outstanding Principal	$ 450,000,000		450,000,000
Premium (Discount)	(6,200,000)		(6,500,000)
Long-Term Debt	$ 443,800,000		443,500,000
Stated interest rate	5.05%						5.05%
Debt instrument, face amount						$ 150,000,000	$ 300,000,000
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
Stated interest rate	5.45%			5.45%
Debt instrument, face amount				$ 500,000,000
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, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
2,019	$ 400
2,020	0
2,021	850
2,022	0
2,023	0
Thereafter	3,100
Subtotal	4,350	$ 3,500
Less: net discount	(6.1)	(6.3)
Less: debt issuance cost	(24.3)	(25.9)
Less: current maturities of long-term debt	(399.8)	0
Long-term debt, net of unamortized issuance cost	$ 3,919.8	$ 3,467.8

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Dec. 11, 2018USD ($)	Jun. 01, 2017USD ($)	May 11, 2017USD ($)	Jul. 14, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jan. 01, 2019USD ($)	May 12, 2015USD ($)	Nov. 12, 2014USD ($)	Sep. 20, 2014USD ($)	Jul. 20, 2014USD ($)	Mar. 19, 2014USD ($)	Mar. 07, 2014USD ($)
Debt Instrument
Debt instrument, premium					$ 6,100,000	$ 6,300,000
Repurchased face amount		$ 162,500,000
Repurchase amount		$ 174,100,000
Gain on extinguishment of debt					0	9,000,000	$ 0
Proceeds from issuance of long-term debt					$ 3,904,000,000	$ 2,315,900,000	$ 2,057,800,000
Redemption price, percentage		103.60%			100.00%
Maximum
Debt Instrument
Stated interest rate					5.60%	5.60%
Minimum
Debt Instrument
Stated interest rate					2.70%	2.70%
ENLK Credit Facility
Debt Instrument
Maximum borrowing capacity					$ 1,500,000,000
Outstanding letters of credit					$ 9,800,000	$ 9,800,000
ENLK Credit Facility | Federal Funds
Debt Instrument
Variable interest rate					0.50%
ENLK Credit Facility | Eurodollar
Debt Instrument
Variable interest rate					1.00%
ENLK Credit Facility | Maximum | LIBOR
Debt Instrument
Variable interest rate					1.75%
ENLK Credit Facility | Maximum | Eurodollar
Debt Instrument
Variable interest rate					0.75%
ENLK Credit Facility | Minimum | LIBOR
Debt Instrument
Variable interest rate					1.00%
ENLK Credit Facility | Minimum | Eurodollar
Debt Instrument
Variable interest rate					0.00%
Term Loan due 2021
Debt Instrument
Debt instrument, premium					$ 0	0
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
Debt instrument, premium														$ (29,500,000)
Repurchased face amount											$ 15,500,000	$ 18,500,000
Repurchase amount											$ 17,000,000	$ 20,000,000
Unsecured Debt
Debt Instrument
Debt instrument, face amount									$ 900,000,000				$ 1,200,000,000
2.70% Senior unsecured notes due 2019
Debt Instrument
Debt instrument, face amount													$ 400,000,000
Stated interest rate					2.70%								2.70%
Debt instrument, premium					$ 0	100,000
Selling price of debt instrument													99.85%
4.40% Senior unsecured notes due 2024
Debt Instrument
Debt instrument, face amount										$ 100,000,000			$ 450,000,000
Stated interest rate					4.40%								4.40%
Debt instrument, premium					$ (1,800,000)	(2,200,000)
Selling price of debt instrument									96.381%	104.007%			99.83%
5.60% Senior unsecured notes due 2044
Debt Instrument
Debt instrument, face amount													$ 350,000,000
Stated interest rate					5.60%								5.60%
Debt instrument, premium					$ 200,000	200,000
Selling price of debt instrument													99.925%
5.05% Senior unsecured notes due 2045
Debt Instrument
Debt instrument, face amount									$ 150,000,000	$ 300,000,000
Stated interest rate					5.05%					5.05%
Debt instrument, premium					$ 6,200,000	6,500,000
Selling price of debt instrument										99.452%
4.15% Senior unsecured notes due 2025
Debt Instrument
Debt instrument, face amount									$ 750,000,000
Stated interest rate					4.15%				4.15%
Debt instrument, premium					$ 900,000	1,000,000
Selling price of debt instrument									99.827%
4.85% Senior unsecured notes due 2026
Debt Instrument
Debt instrument, face amount				$ 500,000,000
Stated interest rate				4.85%	4.85%
Debt instrument, premium					$ 500,000	600,000
Selling price of debt instrument				99.859%
Proceeds from issuance of long-term debt				$ 495,700,000
5.45% Senior unsecured notes due 2047
Debt Instrument
Debt instrument, face amount			$ 500,000,000
Stated interest rate			5.45%		5.45%
Debt instrument, premium					$ 100,000	$ 100,000
Selling price of debt instrument			99.981%
Proceeds from issuance of long-term debt			$ 495,200,000
Letter of Credit | ENLK Credit Facility
Debt Instrument
Maximum borrowing capacity					500,000,000
Unsecured Debt | Term Loan due 2021
Debt Instrument
Debt instrument, face amount	$ 850,000,000				850,000,000
Ratio of consolidated EBITDA to consolidated interest charges	2.50
Ratio of consolidated indebtedness to consolidated EBITDA	5
Ratio of consolidated indebtedness to consolidated EBITDA during an acquisition period	5.50
Unsecured Debt | Term Loan due 2021 | Federal Funds
Debt Instrument
Variable interest rate	0.50%
Unsecured Debt | Term Loan due 2021 | Eurodollar
Debt Instrument
Variable interest rate	1.00%
Unsecured Debt | Term Loan due 2021 | Maximum | LIBOR
Debt Instrument
Variable interest rate	1.75%
Unsecured Debt | Term Loan due 2021 | Maximum | Eurodollar
Debt Instrument
Variable interest rate	0.75%
Unsecured Debt | Term Loan due 2021 | Minimum
Debt Instrument
Conditional acquisition purchase price	$ 50,000,000
Unsecured Debt | Term Loan due 2021 | Minimum | LIBOR
Debt Instrument
Variable interest rate	1.00%
Unsecured Debt | Term Loan due 2021 | Minimum | Eurodollar
Debt Instrument
Variable interest rate	0.00%
ENLC | ENLC Credit Facility
Debt Instrument
Maximum borrowing capacity					$ 250,000,000
Subsequent Event | Consolidated Revolving Credit Facility
Debt Instrument
Maximum borrowing capacity								$ 1,750,000,000

Long-Term Debt - Summary of Red

Long-Term Debt - Summary of Redemption Provision Terms (Details)	12 Months Ended
	Dec. 31, 2018
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%
5.60% 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current income tax provision	$ 1.8	$ 2.6	$ 1.9
Deferred tax benefit	(3.9)	(26.6)	(0.6)
Total income tax provision (benefit)	$ (2.1)	$ (24)	$ 1.3

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	Dec. 22, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Income tax benefit	$ 24,900,000
Deferred tax liability			$ 42,400,000	$ 46,300,000
Unrecognized tax benefits, decrease resulting from prior period tax positions		$ 1,500,000
Unrecognized tax benefits		$ 0	0	0
Clearfield Energy
Business Acquisition [Line Items]
Deferred tax liability			$ 38,700,000	$ 38,800,000

Partners' Capital - Narrative a

Partners' Capital - Narrative and Distribution Activity (Details)	Jan. 25, 2019	May 13, 2016	Sep. 30, 2017USD ($)$ / sharesshares	Jan. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2018USD ($)$ / sharesshares	Mar. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares	Jun. 30, 2017USD ($)$ / sharesshares	Mar. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2016USD ($)$ / sharesshares	Mar. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015shares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Jun. 30, 2017	Nov. 30, 2014USD ($)
Partners' capital
Issuance of common units																		$ 46,100,000	$ 106,900,000	$ 167,500,000
Proceeds from sale of common units																		$ 46,100,000	$ 106,900,000	167,500,000
Common units issued (in shares) | shares					353,117,434				349,702,372									353,117,434	349,702,372
Common units outstanding (in shares) | shares					353,117,434				349,702,372									353,117,434	349,702,372
Percentage of available cash to distribute					100.00%													100.00%
Period after quarter for distribution																		45 days
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
Class C Common Units
Partners' capital
Common units issued (in shares) | shares																	7,075,433
Common units outstanding (in shares) | shares																	7,075,433
Distributions (in shares) | shares																233,107	209,044
Partners capital, common units conversion ratio		1
Series B Preferred Unitholders
Partners' capital
Partners capital, common units conversion ratio				1
Proceeds from issuance of Preferred Units																		$ 0	$ 0	724,100,000
Preferred interest in net income																		90,200,000	86,000,000	69,900,000
Distributions to Preferred Unitholders																		65,000,000	15,900,000	0
Series C Preferred Unitholders
Partners' capital
Proceeds from issuance of Preferred Units																		0	394,000,000	0
Preferred interest in net income																		24,000,000	6,700,000	0
Distributions to Preferred Unitholders																		24,000,000	5,600,000	0
Limited Partner | 2017 EDA
Partners' capital
Commissions																		500,000
Limited Partner | Common Units
Partners' capital
Issuance of common units																		$ 46,100,000	$ 106,900,000	$ 167,500,000
Partners' capital account, units, sold in public offering (in shares) | shares																		2,600,000	6,200,000	10,000,000
Distribution/unit (in dollars per share) | $ / shares					$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39
Limited Partner | Common Units | 2014 EDA
Partners' capital
Agreement for gross sales of common units (up to)																						$ 350,000,000
Issuance of common units																				$ 10,000,000
Proceeds from sale of common units																				167,500,000
Commissions																				$ 1,700,000
Limited Partner | Common Units | 2017 EDA
Partners' capital
Proceeds from sale of common units																		$ 46,100,000	$ 106,900,000
Commissions																			$ 1,100,000
Partners' capital account, units, sold in public offering (in shares) | shares																		2,600,000	6,200,000
Registration fees																			$ 200,000
Limited Partner | Class C Common Units
Partners' capital
Distributions (in shares) | shares																				400,000
Limited Partner | Series B Preferred Unitholders
Partners' capital
Distributions (in shares) | shares																		1,600,000	3,900,000	3,200,000
Partners' capital account, units, sold in private placement (in shares) | shares				50,000,000																50,000,000
Price per share (in dollars per share) | $ / shares			$ 15	$ 15						$ 15
Proceeds from issuance of Preferred Units				$ 724,100,000	$ 16,500,000	$ 16,400,000	$ 16,300,000	$ 16,200,000	$ 16,100,000	$ 15,900,000	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Conversion obligation period of consecutive trading days				30 days														30 days
Average trading price, number of trading days				2 days														2 days
Conversion VWAP percentage				150.00%
Percent of issue price				140.00%														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%
Net income (loss) allocated to preferred																		$ 90,200,000	$ 86,000,000	$ 69,900,000
Preferred units, distributions (in shares) | shares					425,785	422,720	419,678	416,657	413,658	410,681	1,178,672	1,154,147	1,130,131	1,106,616	1,083,589	992,445
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 Preferred Units			$ 394,000,000
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%
Subsequent Event
Partners' capital
Partners capital, common units conversion ratio	1.15

Partners' Capital - Computation

Partners' Capital - Computation of Basic and Diluted Earnings per Limited Partner Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Distributed earnings allocated to:
Total distributed earnings													$ 552.5	$ 545.2	$ 523.5
Undistributed loss allocated to:
Total undistributed loss													(733.3)	(527.3)	(1,185.6)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)	$ (266.5)	$ 5.2	$ 58.9	$ 21.6	$ 36.3	$ (8.6)	$ (0.5)	$ (9.3)	$ (60)	$ (11.4)	$ (23.5)	$ (567.2)	$ (180.8)	$ 17.9	$ (662.1)
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)	$ (0.75)	$ 0.01	$ 0.17	$ 0.06	$ 0.10	$ (0.02)	$ 0	$ (0.03)	$ (0.18)	$ (0.03)	$ (0.07)	$ (1.74)	$ (0.51)	$ 0.05	$ (1.99)
Diluted (in dollars per share)	$ (0.75)	$ 0.01	$ 0.17	$ 0.06	$ 0.10	$ (0.02)	$ 0	$ (0.03)	$ (0.18)	$ (0.03)	$ (0.07)	$ (1.74)	$ (0.51)	$ 0.05	$ (1.99)
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings													$ 4.4	$ 4	$ 3.5
Undistributed loss allocated to:
Total undistributed loss													(5.8)	(3.8)	(8)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)													(1.4)	0.2	(4.5)
Limited Partner | Common Units
Distributed earnings allocated to:
Total distributed earnings													548.1	541.2	520
Undistributed loss allocated to:
Total undistributed loss													(727.5)	(523.5)	(1,177.6)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)													$ (179.4)	$ 17.7	$ (657.6)

Partners' Capital - Unit Amount

Partners' Capital - Unit Amounts Used to Compute Earnings per Limited Partner Unit (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Basic weighted average units outstanding:
Weighted average limited partner basic common units outstanding (in shares)	351,300,000	346,900,000	333,300,000
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Weighted average limited partner basic common units outstanding (in shares)	351,300,000	346,900,000	333,300,000
Dilutive effect of non-vested restricted units (in shares)	0	1,400,000	0
Total weighted average limited partner diluted common units outstanding (in shares)	351,300,000	348,300,000	333,300,000
Class C Common Units
Limited Partners' Capital Account [Line Items]
Weighted average number, diluted, limited partnership units converted adjustment (in shares)			2,740,273

Partners' Capital - Net Income

Partners' Capital - Net Income Allocated to the General Partner (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Incentive
General partner interest in net income	$ 9.1	$ 7.7	$ 11.2	$ 10.6	$ 11	$ 10.6	$ 10.8	$ 5.9	$ 10.7	$ 10.8	$ 10.6	$ 7.4	$ 38.6	$ 38.3	$ 39.5
General Partner Interest
Incentive
Income allocation for incentive distributions													59.5	58.9	56.8
Unit-based compensation attributable to ENLC’s restricted units													(20.3)	(21)	(14.7)
General partner share of net income (loss)													(0.6)	0.4	(2.6)
General partner interest in net income													$ 38.6	$ 38.3	$ 39.5

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments
Net proceeds received		$ 0	$ 189.7	$ 0
Contributions		0.1	12.6	73.8
Distributions		22.7	13.5	57.7
Equity in income		13.3	9.6	$ (19.9)
Total investments in unconsolidated affiliates		$ 80.1	$ 89.4
Gulf Coast Fractionators
Schedule of Equity Method Investments
Ownership interest		38.75%	38.75%	38.75%
Distributions		$ 22.3	$ 12.7	$ 7.5
Equity in income		15.8	12.6	$ 3.4
Total investments in unconsolidated affiliates		41.9	48.4
Howard Energy Partners
Schedule of Equity Method Investments
Ownership interest				31.00%
Net proceeds received	$ 189.7
Contributions		0	0	$ 45
Distributions		0	0	50.2
Equity in income		$ 0	(3.4)	(23.3)
Loss on the sale of disposal of HEP Interests			$ 3.4	20.1
Howard Energy Partners | Preferred Units
Schedule of Equity Method Investments
Contributions				32.7
Distributions				$ 32.7
Cedar Cove JV
Schedule of Equity Method Investments
Ownership interest		30.00%	30.00%	30.00%
Contributions		$ 0.1	$ 12.6	$ 28.8
Distributions		0.4	0.8	0
Equity in income		(2.5)	0.4	$ 0
Total investments in unconsolidated affiliates		$ 38.2	$ 41

Employee Incentive Plans - Long

Employee Incentive Plans - Long Term Incentive Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Compensation allocation
Total unit-based compensation expense	$ 40.8	$ 47.8	$ 30
Cost of unit-based compensation charged to general and administrative expense
Compensation allocation
Total unit-based compensation expense	30	37.1	23.4
Cost of unit-based compensation charged to operating expense
Compensation allocation
Total unit-based compensation expense	$ 10.8	$ 10.7	$ 6.6

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	Jul. 23, 2018	Jul. 18, 2018	Mar. 31, 2018	Mar. 31, 2017	Oct. 31, 2016	Feb. 29, 2016	Jan. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Unvested restricted units
Number of Units
Non-vested, beginning of period (in shares)								1,980,224
Granted (in shares)								1,590,100
Vested (in shares)			(200,753)					(835,115)
Forfeited (in shares)								(178,939)
Non-vested, end of period (in shares)								2,556,270	1,980,224
Aggregate intrinsic value, end of period								$ 28.1
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)								$ 15.81
Granted (in dollars per share)								15.27
Vested (in dollars per share)								19.68
Forfeited (in dollars per share)								12.75
Non-vested, end of period (in dollars per share)								$ 14.43	$ 15.81
Fair value of units vested			$ 3					$ 16.4	$ 22.6	$ 9.5
Units withheld for payroll taxes (in shares)								261,063
Aggregate intrinsic value of units vested								$ 13.1	$ 16.6	4.1
Unrecognized compensation cost related to non-vested restricted incentive units								$ 18.4
Unrecognized compensation costs, weighted average period for recognition								1 year 10 months
Vesting period								3 years
Unvested restricted units | ENLC
Number of Units
Non-vested, beginning of period (in shares)								1,889,310
Granted (in shares)								1,473,195
Vested (in shares)			(194,185)					(769,848)
Forfeited (in shares)								(166,790)
Non-vested, end of period (in shares)								2,425,867	1,889,310
Aggregate intrinsic value, end of period								$ 23
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)								$ 16.33
Granted (in dollars per share)								15.76
Vested (in dollars per share)								21.40
Forfeited (in dollars per share)								12.74
Non-vested, end of period (in dollars per share)								$ 14.62	$ 16.33
Fair value of units vested			$ 3					$ 16.5	$ 22.2	12.4
Units withheld for payroll taxes (in shares)								244,123
Aggregate intrinsic value of units vested								$ 12.8	$ 15.3	$ 4.1
Unrecognized compensation cost related to non-vested restricted incentive units								$ 17.9
Unrecognized compensation costs, weighted average period for recognition								1 year 10 months
Vesting period								3 years
Performance Units
Number of Units
Non-vested, beginning of period (in shares)								585,285
Granted (in shares)								256,345
Vested (in shares)		(120,250)						(313,610)	0	0
Forfeited (in shares)								(76,351)
Non-vested, end of period (in shares)								451,669	585,285
Aggregate intrinsic value, end of period								$ 5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)								$ 20.52
Granted (in dollars per share)								19.24
Vested (in dollars per share)								24.43
Forfeited (in dollars per share)								16.62
Non-vested, end of period (in dollars per share)								$ 17.74	$ 20.52
Fair value of units vested								$ 7.7
Units withheld for payroll taxes (in shares)								112,101
Aggregate intrinsic value of units vested								$ 5
Unrecognized compensation cost related to non-vested restricted incentive units								$ 6.1
Unrecognized compensation costs, weighted average period for recognition								1 year 8 months
Additional compensation expense not yet recognized								$ 2.3
Vesting period								3 years
Grant date fair value assumptions
TSR price (in dollars per share)			$ 15.44	$ 17.55	$ 17.71	$ 14.82	$ 14.82
Risk-free interest rate			2.38%	1.62%	0.91%	0.89%	1.10%
Volatility factor			43.85%	43.94%	44.62%	42.33%	39.71%
Distribution yield			10.50%	8.70%	8.80%	19.20%	12.10%
Performance Units | ENLC
Number of Units
Non-vested, beginning of period (in shares)								548,839
Granted (in shares)								223,865
Vested (in shares)		(109,819,000,000)						(283,637)	0	0
Forfeited (in shares)								(70,918)
Non-vested, end of period (in shares)								418,149	548,839
Aggregate intrinsic value, end of period								$ 4
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)								$ 22.14
Granted (in dollars per share)								21.63
Vested (in dollars per share)								27.25
Forfeited (in dollars per share)								17.75
Non-vested, end of period (in dollars per share)								$ 19.15	$ 22.14
Fair value of units vested								$ 7.7
Units withheld for payroll taxes (in shares)								100,109,000,000
Aggregate intrinsic value of units vested								$ 4.7
Unrecognized compensation cost related to non-vested restricted incentive units								$ 5.9
Unrecognized compensation costs, weighted average period for recognition								1 year 7 months
Additional compensation expense not yet recognized								$ 2.1
Vesting period								3 years
Grant date fair value assumptions
TSR price (in dollars per share)			$ 16.55	$ 18.29	$ 16.75	$ 15.38	$ 15.38
Risk-free interest rate			2.38%	1.62%	0.91%	0.89%	1.10%
Volatility factor			51.36%	52.07%	52.89%	52.05%	46.02%
Distribution yield			6.70%	5.40%	6.10%	14.00%	8.60%
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%							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	100.00%							200.00%

Employee Incentive Plans - Bene

Employee Incentive Plans - Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [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	$ 8.3	$ 7.6	$ 7.4

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	May 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) reclassified to earnings	$ 0	$ 0
Settlement gain (loss)	(2.1)	$ (2.1)		$ (2.2)
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	$ (0.1)
Settlement gains on derivatives			$ 0.4

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments
Realized gain (loss) on derivatives			$ 0.4
Gain (loss) on derivative activity	$ 5.2	$ (4.2)	(11.1)
Commodity Swaps
Derivative Instruments
Change in fair value of derivatives	10.1	4.7	(20.1)
Realized gain (loss) on derivatives	(4.9)	(8.9)	9
Gain (loss) on derivative activity	$ 5.2	$ (4.2)	$ (11.1)

Derivatives - Assets and Liabil

Derivatives - Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivative assets — current	$ 28.6	$ 6.8
Fair value of derivative assets — long-term	4.1	0
Fair value of derivative liabilities — current	(21.8)	(8.4)
Fair value of derivative liabilities — long-term	(2.4)	0
Net fair value of derivatives	$ 8.5	$ (1.6)

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBTUgalMMBbls	Dec. 31, 2017USD ($)
Derivative
Fair Value	$ 8.5	$ (1.6)
Commodity
Derivative
Fair Value	8.5
Maximum loss if counterparties fail to perform	32.7
Possible reduction in maximum loss if counterparties fail to perform	$ 9.4
Commodity | NGL | Short
Derivative
Notional amount (in gallons or mmbbls) | gal	29
Fair Value	$ 4.5
Commodity | NGL | Long
Derivative
Notional amount (in gallons or mmbbls) | gal	7.7
Fair Value	$ 0.1
Commodity | Natural Gas | Short
Derivative
Notional amount (in mmbtu) | MMBTU	9
Fair Value	$ (1.6)
Commodity | Natural Gas | Long
Derivative
Notional amount (in mmbtu) | MMBTU	14.9
Fair Value	$ (1.5)
Commodity | Condensate | Short
Derivative
Notional amount (in gallons or mmbbls) | MMBbls	12.9
Fair Value	$ 23.6
Commodity | Condensate | Long
Derivative
Notional amount (in gallons or mmbbls) | MMBbls	0
Fair Value	$ (16.6)

Fair Value Measurements - Measu

Fair Value Measurements - Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Measured at fair value
Fair Value	$ 8.5	$ (1.6)
Level 2 | Commodity Swaps | Recurring
Measured at fair value
Fair Value	$ 8.5	$ (1.6)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value
Debt issuance costs	$ 24.3	$ 25.9
Senior unsecured notes	$ 3,500	$ 3,500
Minimum
Fair Value
Stated interest rate	2.70%	2.70%
Maximum
Fair Value
Stated interest rate	5.60%	5.60%
Carrying Value
Fair Value
Long-term debt	$ 4,319.6	$ 3,467.8
Installment Payables	0	249.5
Obligations under capital lease	2.5	4.1
Secured term loan receivable	51.1	0
Fair Value
Fair Value
Long-term debt	3,953.6	3,575.6
Installment Payables	0	249.6
Obligations under capital lease	2.2	3.4
Secured term loan receivable	$ 51.1	$ 0

Commitments and Contingencies_2

Commitments and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2014	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,019		$ 14.1
2,020		10.3
2,021		8.7
2,022		8.6
2,023		8.8
Thereafter		49.8
Total		100.3
Rent expense		$ 52.5	$ 54.5	$ 59.6
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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting
Revenue from contracts with customers														$ 7,693.8
Cost of sales	[1]													(6,008)	$ (4,361.5)	$ (3,015.5)
Operating expenses														(453.4)	(418.7)	(398.5)
Gain (loss) on derivative activity														5.2	(4.2)	(11.1)
Segment profit (loss)														1,237.6	959.4	838.4
Depreciation and amortization														(577.3)	(545.3)	(503.9)
Impairments		$ (341.2)	$ (24.6)	$ 0	$ 0	$ (8.3)	$ (1.8)	$ 0	$ (7)	$ 0	$ 0	$ 0	$ (566.3)	(365.8)	(17.1)	(566.3)
Goodwill		190.3				422.3				422.3				190.3	422.3	422.3
Capital expenditures														849.9	768.1	676.1
Total identifiable assets		9,571.3				9,414				9,153.4				9,571.3	9,414	9,153.4
Corporate
Segment Reporting
Revenue from contracts with customers														(1,245)
Cost of sales														1,245	882.1	419.8
Operating expenses														0	0	0
Gain (loss) on derivative activity														5.2	(4.2)	(11.1)
Segment profit (loss)														5.2	(4.2)	(11.1)
Depreciation and amortization														(8.7)	(9.9)	(9.2)
Impairments														0	0	0
Goodwill		0				0				0				0	0	0
Capital expenditures														5.3	26.4	9.1
Total identifiable assets		222.3				144.5				300.2				222.3	144.5	300.2
Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														1,394.6
Cost of sales														(753.9)	(772.3)	(483.4)
Operating expenses														(180.6)	(172.7)	(168.5)
Gain (loss) on derivative activity														0	0	0
Segment profit (loss)														460.1	420.9	416.4
Depreciation and amortization														(216.2)	(215.2)	(196.9)
Impairments														(232)	0	(473.1)
Goodwill		0				232				232				0	232	232
Capital expenditures														249.4	145.4	217.9
Total identifiable assets		2,925.3				3,094.8				3,142.6				2,925.3	3,094.8	3,142.6
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3,501.2
Cost of sales														(3,158.7)	(2,618.1)	(1,729)
Operating expenses														(108.3)	(101.3)	(96.6)
Gain (loss) on derivative activity														0	0	0
Segment profit (loss)														234.2	212.2	175.9
Depreciation and amortization														(122.7)	(116.1)	(114.8)
Impairments														(24.6)	(0.8)
Goodwill		0				0				0				0	0	0
Capital expenditures														47	75.1	79.1
Total identifiable assets		2,347.9				2,408.5				2,349.3				2,347.9	2,408.5	2,349.3
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														1,297.7
Cost of sales														(744)	(522.9)	(184.9)
Operating expenses														(89.2)	(64.6)	(52.1)
Gain (loss) on derivative activity														0	0	0
Segment profit (loss)														464.5	287.3	200
Depreciation and amortization														(178.1)	(156.6)	(140.6)
Impairments														0	0
Goodwill		190.3				190.3				190.3				190.3	190.3	190.3
Capital expenditures														412.5	442.1	295.7
Total identifiable assets		3,116.5				2,836.7				2,524.5				3,116.5	2,836.7	2,524.5
Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,745.3
Cost of sales														(2,596.4)	(1,330.3)	(1,038)
Operating expenses														(75.3)	(80.1)	(81.3)
Gain (loss) on derivative activity														0	0	0
Segment profit (loss)														73.6	43.2	57.2
Depreciation and amortization														(51.6)	(47.5)	(42.4)
Impairments														(109.2)	(16.3)	(93.2)
Goodwill		0				0				0				0	0	0
Capital expenditures														135.7	79.1	74.3
Total identifiable assets		$ 959.3				$ 929.5				$ 836.8				959.3	929.5	836.8
Product sales
Segment Reporting
Revenue from contracts with customers														6,512.3	4,358.4	3,008.9
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers														0	0	0
Product sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														321.5	325	237.2
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3,317.9	2,529.6	1,632.5
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														215.6	128.8	48.5
Product sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,657.3	1,375	1,090.7
Natural gas sales
Segment Reporting
Revenue from contracts with customers														1,013.7
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers														0
Natural gas sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														292.9
Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														531.1
Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														189.7
Natural gas sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL sales
Segment Reporting
Revenue from contracts with customers														2,841
NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers														0
NGL sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														28.6
NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,786.3
NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														25.2
NGL sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.9
Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers														2,657.6
Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers														0
Crude oil and condensate sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.5
Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.7
Crude oil and condensate sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														2,656.4
Product sales—related parties
Segment Reporting
Revenue from contracts with customers														41	144.9	134.3
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(1,241.7)	(750.6)	(333)
Product sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														552.8	500.3	287.6
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														47.7	45	57.8
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														678.9	349.4	120.4
Product sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.3	0.8	1.5
Natural gas sales—related parties
Segment Reporting
Revenue from contracts with customers														2.5
Natural gas sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														0
Natural gas sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Natural gas sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Natural gas sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														2.5
Natural gas sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL sales—related parties
Segment Reporting
Revenue from contracts with customers														37.4
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(1,104.3)
NGL sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														503.5
NGL sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														47.4
NGL sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														590.8
NGL sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude oil and condensate sales—related parties
Segment Reporting
Revenue from contracts with customers														1.1
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(137.4)
Crude oil and condensate sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														49.3
Crude oil and condensate sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.3
Crude oil and condensate sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														85.6
Crude oil and condensate sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.3
Midstream services
Segment Reporting
Revenue from contracts with customers														763.3	552.3	467.2
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers														0	0	0
Midstream services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														288.5	116.3	104.2
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														132.3	220.6	215.4
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														272.7	155	82.2
Midstream services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														69.8	60.4	65.4
Gathering and transportation
Segment Reporting
Revenue from contracts with customers														398.9
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers														0
Gathering and transportation | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														177.9
Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														68.8
Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														149.1
Gathering and transportation | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.1
Processing
Segment Reporting
Revenue from contracts with customers														227.1
Processing | Corporate
Segment Reporting
Revenue from contracts with customers														0
Processing | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														101
Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.3
Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														122.8
Processing | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services
Segment Reporting
Revenue from contracts with customers														59.6
NGL services | Corporate
Segment Reporting
Revenue from contracts with customers														0
NGL services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														59.6
NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services
Segment Reporting
Revenue from contracts with customers														67.1
Crude services | Corporate
Segment Reporting
Revenue from contracts with customers														0
Crude services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.6
Crude services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														66.5
Other services
Segment Reporting
Revenue from contracts with customers														10.6
Other services | Corporate
Segment Reporting
Revenue from contracts with customers														0
Other services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														9.6
Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.6
Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.2
Other services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.2
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers														377.2	688.2	653.1
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(3.3)	(131.5)	(86.8)
Midstream services—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														231.8	424.3	439.3
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.3	136.4	95.8
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														130.5	241.6	185.9
Midstream services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														14.9	$ 17.4	$ 18.9
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 | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														122.7
Gathering and transportation—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Gathering and transportation—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														80.6
Gathering and transportation—related parties | Crude and Condensate | 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 | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														108.6
Processing—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Processing—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														48.4
Processing—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services—related parties
Segment Reporting
Revenue from contracts with customers														0
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														(3.3)
NGL services—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														3.3
NGL services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
NGL services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services—related parties
Segment Reporting
Revenue from contracts with customers														16.4
Crude services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers														0
Crude services—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Crude services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														1.5
Crude services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														14.9
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 | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers														0.5
Other services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Other services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers														0
Other services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers														$ 0
[1]	Includes related party cost of sales of $114.1 million, $211.0 million, and $150.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Segment profit													$ 1,237.6	$ 959.4	$ 838.4
General and administrative expenses													(130.2)	(123.5)	(119.3)
Depreciation and amortization													(577.3)	(545.3)	(503.9)
Loss on disposition of assets													(0.4)	0	(13.2)
Impairments	$ (341.2)	$ (24.6)	$ 0	$ 0	$ (8.3)	$ (1.8)	$ 0	$ (7)	$ 0	$ 0	$ 0	$ (566.3)	(365.8)	(17.1)	(566.3)
Gain on litigation settlement													0	26	0
Operating income (loss)	$ (185.3)	$ 92.5	$ 150.1	$ 106.6	$ 98.1	$ 73.4	$ 70.4	$ 57.6	$ 38.3	$ 66.9	$ 46.4	$ (515.9)	$ 163.9	$ 299.5	$ (364.3)

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 2,058.3	$ 2,114.3	$ 1,764.7	$ 1,761.7	$ 1,756.2	$ 1,397.9	$ 1,263.6	$ 1,321.9	$ 1,224.9	$ 1,104.6	$ 1,033.2	$ 889.7	$ 7,699	$ 5,739.6	$ 4,252.4
Impairments	341.2	24.6	0	0	8.3	1.8	0	7	0	0	0	566.3	365.8	17.1	566.3
Operating income (loss)	(185.3)	92.5	150.1	106.6	98.1	73.4	70.4	57.6	38.3	66.9	46.4	(515.9)	163.9	299.5	(364.3)
Net income (loss) attributable to ENLK	(230.2)	43.2	98.9	60.1	75.7	25.5	29.6	18.1	(28.6)	18.8	5	(560.4)	(28)	148.9	(565.2)
General partner interest in net income	9.1	7.7	11.2	10.6	11	10.6	10.8	5.9	10.7	10.8	10.6	7.4	38.6	38.3	39.5
Limited partners’ interest in net income (loss) attributable to ENLK	$ (266.5)	$ 5.2	$ 58.9	$ 21.6	$ 36.3	$ (8.6)	$ (0.5)	$ (9.3)	$ (60)	$ (11.4)	$ (23.5)	$ (567.2)	$ (180.8)	$ 17.9	$ (662.1)
Net income (loss) attributable to ENLK per limited partners’ unit:
Basic common unit (in dollars per share)	$ (0.75)	$ 0.01	$ 0.17	$ 0.06	$ 0.10	$ (0.02)	$ 0	$ (0.03)	$ (0.18)	$ (0.03)	$ (0.07)	$ (1.74)	$ (0.51)	$ 0.05	$ (1.99)
Diluted common unit (in dollars per share)	$ (0.75)	$ 0.01	$ 0.17	$ 0.06	$ 0.10	$ (0.02)	$ 0	$ (0.03)	$ (0.18)	$ (0.03)	$ (0.07)	$ (1.74)	$ (0.51)	$ 0.05	$ (1.99)

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	Jan. 07, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental disclosures of cash flow information:
Cash paid for interest		$ 182.6	$ 163.8	$ 132.5
Cash paid for income taxes		1.5	4.8	2.8
Non-cash investing activities:
Non-cash accrual of property and equipment		6.8	(22.7)	13.1
Discounted secured term loan receivable from contract restructuring		47.7	0	0
EOGP
Non-cash financing activities:
Installment payable, net of discount of $79.1 million	$ 420.9	0	0	420.9
Installment payable discount	$ 79.1			79.1
Contribution from ENLC		$ 0	$ 0	$ 237.1

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Current Assets:
Natural gas and NGLs inventory	$ 41.3	$ 30.1
Secured term loan receivable from contract restructuring, net of discount of $1.1	19.4	0
Secured term loan receivable, discount	1.1	0
Prepaid expenses and other	12.1	9.6
Natural gas and NGLs inventory, prepaid expenses, and other	72.8	39.7
Other Current Liabilities:
Accrued interest	37.3	35.4
Accrued wages and benefits, including taxes	37.2	30.4
Accrued ad valorem taxes	28.1	27.8
Capital expenditure accruals	50.6	48.8
Onerous performance obligations	9	15.2
Other	84.5	64.8
Other current liabilities	$ 246.7	$ 222.4

Subsequent Events (Details)

Subsequent Events (Details)	Jan. 31, 2019shares	Jan. 25, 2019USD ($)	Jan. 01, 2019USD ($)segment	Dec. 31, 2018USD ($)
Subsequent Event
Subsequent Event [Line Items]
Partners capital, common units conversion ratio		1.15
Number of operating segments | segment			4
ENLK Credit Facility
Subsequent Event [Line Items]
Maximum borrowing capacity				$ 1,500,000,000
ENLC Credit Facility | ENLC
Subsequent Event [Line Items]
Maximum borrowing capacity				250,000,000
Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity			$ 1,750,000,000
Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity			2,250,000,000
Ratio of consolidated EBITDA to consolidated interest charges		2.50
Ratio of consolidated indebtedness to consolidated EBITDA		5
Ratio of consolidated indebtedness to consolidated EBITDA during an acquisition period		5.50
Letter of Credit | ENLK Credit Facility
Subsequent Event [Line Items]
Maximum borrowing capacity				500,000,000
Revolving Credit Facility | Line of Credit | ENLK Credit Facility
Subsequent Event [Line Items]
Maximum borrowing capacity				1,500,000,000
Revolving Credit Facility | Line of Credit | ENLC Credit Facility | ENLC
Subsequent Event [Line Items]
Maximum borrowing capacity				$ 250,000,000
Revolving Credit Facility | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity			1,750,000,000
Revolving Credit Facility | Letter of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity			$ 500,000,000
Minimum | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Conditional acquisition purchase price		$ 0
Eurodollar | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				1.00%
Eurodollar | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		1.00%
Eurodollar | Minimum | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				0.00%
Eurodollar | Minimum | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		0.125%
Eurodollar | Maximum | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				0.75%
Eurodollar | Maximum | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		1.00%
LIBOR | Minimum | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				1.00%
LIBOR | Minimum | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		1.125%
LIBOR | Maximum | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				1.75%
LIBOR | Maximum | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		2.00%
Federal Funds | ENLK Credit Facility
Subsequent Event [Line Items]
Variable interest rate				0.50%
Federal Funds | Line of Credit | Consolidated Revolving Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Variable interest rate		0.50%
ENLC | Subsequent Event
Subsequent Event [Line Items]
Shares issued for transfer of ownership (in shares) | shares	55,827,221
EOGP | ENLC
Subsequent Event [Line Items]
Noncontrolling interest percentage				16.10%
EOGP | ENLC | Subsequent Event
Subsequent Event [Line Items]
Noncontrolling interest percentage	16.10%