EnLink Midstream Partners (ENLK) 10-Q 7 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 01, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Document Fiscal Period Focus	Q3
Document Period End Date	Sep. 30, 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
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		353,100,985

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 63.6	$ 30.8
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	198	50.1
Accrued revenue and other	817.2	576.6
Related party	0.7	102.7
Fair value of derivative assets	12.5	6.8
Natural gas and NGLs inventory, prepaid expenses, and other	153.4	39.7
Total current assets	1,245.4	806.7
Property and equipment, net of accumulated depreciation of $2,859.3 and $2,533.0, respectively	6,875.7	6,587
Intangible assets, net of accumulated amortization of $391.3 and $298.7, respectively	1,404.5	1,497.1
Goodwill	422.3	422.3
Investment in unconsolidated affiliates	84.5	89.4
Other assets, net	41.2	11.5
Total assets	10,073.6	9,414
Current liabilities:
Accounts payable and drafts payable	130.6	66.9
Accounts payable to related party	5	18.4
Accrued gas, NGLs, condensate, and crude oil purchases	656.9	476.1
Fair value of derivative liabilities	21.9	8.4
Installment payable, net of discount of $0.5 at December 31, 2017	0	249.5
Current maturities of long-term debt	399.6	0
Other current liabilities	259.8	222.4
Total current liabilities	1,473.8	1,041.7
Long-term debt	3,835.9	3,467.8
Asset retirement obligations	14.6	14.2
Other long-term liabilities	20.7	33.9
Deferred tax liability	44.4	46.3
Fair value of derivative liabilities	7	0
Redeemable non-controlling interest	6.2	4.6
Partners’ equity:
Common unitholders (353,098,287 and 349,702,372 units issued and outstanding, respectively)	2,519.8	2,791.6
General partner interest (1,594,974 equivalent units outstanding)	206.2	207.3
Accumulated other comprehensive loss	(2.1)	(2.1)
Non-controlling interest	661.4	549.5
Total partners’ equity	4,671	4,805.5
Total liabilities and partners’ equity	10,073.6	9,414
Series B Preferred Unitholders
Partners’ equity:
Preferred unitholders	884.6	864.1
Series C Preferred Unitholders
Partners’ equity:
Preferred unitholders	$ 401.1	$ 395.1

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets [Abstract]
Allowance for bad debt	$ 0.3	$ 0.3
Accumulated depreciation	2,859.3	2,533
Accumulated amortization	391.3	298.7
Liabilities [Abstract]
Discount of installment payable, current	$ 0	$ 0.5
Partners’ equity:
Common units issued (in shares)	353,098,287	349,702,372
Common units outstanding (in shares)	353,098,287	349,702,372
General partner interest, equivalent units outstanding (in shares)	1,594,974	1,594,974
Series B Preferred Unitholders
Partners’ equity:
Preferred units issued (in shares)	58,306,274	57,056,281
Preferred unit outstanding (in shares)	58,306,274	57,056,281
Series C Preferred Unitholders
Partners’ equity:
Preferred unit outstanding (in shares)	400,000	400,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Revenue from contracts with customers		$ 2,119.7		$ 5,660.8
Loss on derivative activity		(5.4)	$ (5.5)	(20.1)	$ (1.1)
Total revenues		2,114.3	1,397.9	5,640.7	3,983.4
Operating costs and expenses:
Cost of sales	[1]	1,696.6	1,053.2	4,403.7	2,987.9
Operating expenses		114.7	102.1	337.3	308.8
General and administrative		39.2	30	94.5	94.6
Loss on disposition of assets		0	1.1	1.3	0.8
Depreciation and amortization		146.7	136.3	430.1	407.1
Impairments		24.6	1.8	24.6	8.8
Gain on litigation settlement		0	0	0	(26)
Total operating costs and expenses		2,021.8	1,324.5	5,291.5	3,782
Operating income		92.5	73.4	349.2	201.4
Other income (expense):
Interest expense, net of interest income		(44.1)	(48.9)	(131.5)	(140.5)
Gain on extinguishment of debt		0	0	0	9
Income from unconsolidated affiliates		4.3	4.4	11.7	5
Other income		0.1	0.3	0.3	0.5
Total other expense		(39.7)	(44.2)	(119.5)	(126)
Income before non-controlling interest and income taxes		52.8	29.2	229.7	75.4
Income tax benefit (provision)		(0.9)	(0.5)	0.2	(0.7)
Net income		51.9	28.7	229.9	74.7
Net income attributable to non-controlling interest		8.7	3.2	27.7	1.5
Net income attributable to ENLK		43.2	25.5	202.2	73.2
General partner interest in net income		7.7	10.6	29.5	27.3
Limited partners’ interest in net income (loss) attributable to ENLK		$ 5.2	$ (8.6)	$ 85.7	$ (18.4)
Net income (loss) attributable to ENLK per limited partners’ unit:
Basic common unit (in dollars per share)		$ 0.01	$ (0.02)	$ 0.24	$ (0.05)
Diluted common unit (in dollars per share)		$ 0.01	$ (0.02)	$ 0.24	$ (0.05)
Series B Preferred Unitholders
Other income (expense):
Preferred interest in net income attributable to ENLK		$ 24.3	$ 22.8	$ 69	$ 63.6
Series C Preferred Unitholders
Other income (expense):
Preferred interest in net income attributable to ENLK		6	0.7	18	0.7
Product sales—related parties
Revenues:
Revenue from contracts with customers		10.2	35.3	41	107.3
Midstream services
Revenues:
Revenue from contracts with customers		241.5	136.4	476.1	395.7
Midstream services—related parties
Revenues:
Revenue from contracts with customers		35.8	175	377.2	507.6
Product sales
Revenues:
Revenue from contracts with customers		$ 1,832.2	$ 1,056.7	$ 4,766.5	$ 2,973.9
[1]	Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Related party cost of sales	$ 23	$ 47.3	$ 103.8	$ 126.9

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 51.9	$ 28.7	$ 229.9	$ 74.7
Loss on designated cash flow hedge	0	0	0	(2.2)
Comprehensive income	51.9	28.7	229.9	72.5
Comprehensive income attributable to non-controlling interest	8.7	3.2	27.7	1.5
Comprehensive income attributable to EnLink Midstream Partners, LP	$ 43.2	$ 25.5	$ 202.2	$ 71

Consolidated Statement of Chang

Consolidated Statement of Changes in Partners' Equity - 9 months ended Sep. 30, 2018 - USD ($) shares in Millions, $ in Millions	Total	Non-Controlling Interest	Redeemable Noncontrolling Interest	Accumulated Other Comprehensive Loss	General Partner Interest	Common UnitsLimited Partner	Series B Preferred UnitholdersLimited Partner	Series C Preferred UnitholdersLimited Partner
Beginning balance at Dec. 31, 2017	$ 4,805.5	$ 549.5		$ (2.1)	$ 207.3	$ 2,791.6	$ 864.1	$ 395.1
Beginning balance (in shares) at Dec. 31, 2017					1.6	349.7	57.1	0.4
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	32.1				$ 15.7	$ 16.4
Distributions	(557.4)	(37.6)			(46.3)	(413)	$ (48.5)	$ (12)
Distributions (in shares)							1.2
Contributions from non-controlling interests	122	122
Fair value adjustment related to redeemable non-controlling interest	(1.4)		$ 1.4			(1.4)
Net income	229.7	27.5	0.2		29.5	85.7	$ 69	18
Ending balance at Sep. 30, 2018	4,671	661.4		$ (2.1)	$ 206.2	$ 2,519.8	$ 884.6	$ 401.1
Ending balance (in shares) at Sep. 30, 2018					1.6	353.1	58.3	0.4
Beginning balance at Dec. 31, 2017			4.6
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest	(1.4)		1.4			$ (1.4)
Net income	$ 229.7	$ 27.5	0.2		$ 29.5	$ 85.7	$ 69	$ 18
Ending balance at Sep. 30, 2018			$ 6.2

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income	$ 229.9	$ 74.7
Adjustments to reconcile net income to net cash provided by operating activities:
Impairments	24.6	8.8
Depreciation and amortization	430.1	407.1
Non-cash unit-based compensation	31.6	38.7
Loss on derivatives recognized in net income	20.1	1.1
Gain on extinguishment of debt	0	(9)
Cash settlements on derivatives	(4.3)	(5.9)
Amortization of debt issue costs, net discount (premium) of notes and installment payable	3.2	21.6
Distribution of earnings from unconsolidated affiliates	14	4.1
Income from unconsolidated affiliates	(11.7)	(5)
Non-cash revenue from contract restructuring	(45.5)	0
Other operating activities	(2.2)	1.1
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	(292.2)	(56.9)
Natural gas and NGLs inventory, prepaid expenses, and other	(92.9)	(48.6)
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities	239.1	101.2
Net cash provided by operating activities	543.8	533
Cash flows from investing activities:
Additions to property and equipment	(639.4)	(662.5)
Proceeds from sale of unconsolidated affiliate investment	0	189.7
Investment in unconsolidated affiliates	(0.1)	(11.8)
Distribution from unconsolidated affiliates in excess of earnings	2.7	7.3
Other investing activities	3.8	2
Net cash used in investing activities	(633)	(475.3)
Cash flows from financing activities:
Proceeds from borrowings	1,979	2,151.9
Payments on borrowings	(1,214)	(1,940.3)
Payment of installment payable for EOGP acquisition	(250)	(250)
Debt financing costs	0	(5.5)
Conversion of restricted units, net of units withheld for taxes	(5.6)	(5.2)
Proceeds from issuance of common units	46.1	92.3
Proceeds from issuance of Series C Preferred Units	0	393.7
Distributions to non-controlling interests	(37.6)	(17)
Contributions by non-controlling interests, including contributions from affiliates of $48.6 and $59.3, respectively	122	105.5
Distributions to common unitholders and to general partner	(459.3)	(452.3)
Other financing activities	1.9	(0.7)
Net cash provided by financing activities	122	72.4
Net increase in cash and cash equivalents	32.8	130.1
Cash and cash equivalents, beginning of period	30.8	11.6
Cash and cash equivalents, end of period	63.6	141.7
Supplemental disclosures of cash flow information:
Cash paid for interest	106.3	93.2
Cash paid for income taxes	0.6	3.6
Non-cash investing activities:
Non-cash accrual of property and equipment	13.3	(26.2)
Discounted secured term loan receivable from contract restructuring	47.7	0
Series B Preferred Unitholders
Cash flows from financing activities:
Distributions to Preferred Units	(48.5)	0
Series C Preferred Unitholders
Cash flows from financing activities:
Distributions to Preferred Units	$ (12)	$ 0

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Proceeds from affiliates	$ 122	$ 105.5
Affiliates
Proceeds from affiliates	$ 48.6	$ 59.3

General

General	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	(1) General In this report, the term “Partnership,” as well as the terms “ENLK,” “our,” “we,” “us,” and “its” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership and EOGP. Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information. (a) Organization of Business EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, 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 an indirect, wholly-owned subsidiary of ENLC. ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” 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 Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the managing member of ENLC, which amount 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 at the closing date. Through this transaction, GIP acquired control of (i) the managing member of ENLC, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s indirect ownership of ENLK’s general partner; and • GIP, through GIP Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which amount to approximately 63.8% of the outstanding limited liability company interests in ENLC at the closing date. On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC , and NOLA Merger Sub, LLC, a wholly-owned subsidiary of ENLC (“NOLA Merger Sub”), entered into a definitive agreement and plan of merger (the “Merger Agreement”) pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, NOLA Merger Sub will merge with and into ENLK (the “Merger”), with ENLK continuing as the surviving entity and a subsidiary of ENLC. The Merger and the other transactions contemplated by the Merger Agreement and the preferred restructuring agreement entered into concurrently with the Merger Agreement (the “Merger Transactions”) are expected to close in the first quarter of 2019, subject to obtaining our unitholder approval, customary regulatory approvals, and other customary closing conditions. See Note 13—Subsequent Event for more information regarding this transaction. (b) Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. (b) Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales —Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services —Midstream services represent all other revenue generated as a result of performing our midstream services as 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 three and nine months ended September 30, 2018 , the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $179 million and $480 million , respectively, or 8% and 8% , respectively, 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 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Product sales $ (71 ) $ (149 ) Product sales—related parties (7 ) (53 ) Midstream services (98 ) (251 ) Midstream services—related parties (3 ) (27 ) Total $ (179 ) $ (480 ) 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. 2018 (remaining) $ 190.9 2019 237.1 2020 225.7 2021 82.3 2022 71.9 Thereafter 231.2 Total $ 1,039.1 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 three and nine months ended September 30, 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 11—Segment Information for the revenue disaggregation information included in the segment information table for the three and nine months ended September 30, 2018 . As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the three and nine months ended September 30, 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. (c) 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 are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. 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. While we are still evaluating the complete population of lease contracts, we believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by less than $100 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. (d) Property & Equipment Impairment Review. In accordance with ASC 360, Property, Plant and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets 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 loss is recognized equal to the excess of the asset’s carrying value over its fair value. For the three and nine months ended September 30, 2018 , we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets, because the carrying values were no longer recoverable. For the three and nine months ended September 30, 2017 , we recognized impairments of property and equipment of $1.8 million and $8.8 million , respectively, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well.

Intangible Assets

Intangible Assets	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	(3) Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 5 to 20 years . The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Nine Months Ended September 30, 2018 Customer relationships, beginning of period $ 1,795.8 $ (298.7 ) $ 1,497.1 Amortization expense — (92.6 ) (92.6 ) Customer relationships, end of period $ 1,795.8 $ (391.3 ) $ 1,404.5 The weighted average amortization period is 15.0 years . Amortization expense was $30.9 million and $31.2 million for the three months ended September 30, 2018 and 2017 , respectively, and $92.6 million and $96.2 million for the nine months ended September 30, 2018 and 2017 , respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2018 (remaining) $ 30.9 2019 123.7 2020 123.7 2021 123.7 2022 123.7 Thereafter 878.8 Total $ 1,404.5

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. 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—General 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. From July 1, 2018 to July 18, 2018 and January 1, 2018 to July 18, 2018, Devon accounted for 2.0% and 7.3% of our revenues, respectively, and for the three and nine months ended September 30, 2017 , Devon accounted for 15.0% and 15.4% of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million at December 31, 2017 . Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million at December 31, 2017 . For the three and nine months ended September 30, 2018 , we recorded cost of sales of $11.3 million and $33.8 million , respectively, and for the three and nine months ended September 30, 2017 , we recorded cost of sales of $9.5 million and $15.0 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 September 30, 2018 . Additionally, we had an accounts payable balance related to transactions with the Cedar Cove JV of $5.0 million at September 30, 2018 . The accounts receivable and payable balances related to transactions with the Cedar Cove JV were immaterial at December 31, 2017 . Management believes these transactions are executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of September 30, 2018 and December 31, 2017 , long-term debt consisted of the following (in millions): September 30, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Credit facility due 2020 (1) $ 765.0 $ — $ 765.0 $ — $ — $ — 2.70% Senior unsecured notes due 2019 (2) 400.0 (0.1 ) 399.9 400.0 (0.1 ) 399.9 4.40% Senior unsecured notes due 2024 550.0 1.9 551.9 550.0 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, including current maturities of long-term debt $ 4,265.0 $ (6.1 ) 4,258.9 $ 3,500.0 $ (6.3 ) 3,493.7 Debt issuance cost (3) (23.4 ) (25.9 ) Less: Current maturities of long-term debt (2) (399.6 ) — Long-term debt, net of unamortized issuance cost $ 3,835.9 $ 3,467.8 (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.1% at September 30, 2018 . (2) 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 September 30, 2018 . (3) Net of amortization of $14.5 million and $12.0 million at September 30, 2018 and December 31, 2017 , respectively. Credit Facility We have a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 million letter of credit subfacility. Under our credit facility, we are permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under our credit facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions, extend the maturity date of our credit facility by one year on each occasion. Our credit facility contains certain financial, operational, and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in our credit facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters. Borrowings under our credit facility bear 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 vary depending on our credit rating. If we breach certain covenants governing our credit facility, amounts outstanding under our credit facility, if any, may become due and payable immediately. On June 20, 2018, we amended the change of control provisions of our credit facility to, among other things, designate GIP as Qualifying Owners (as defined in the credit facility). At September 30, 2018 , we were in compliance and expect to be in compliance with the covenants in our credit facility for at least the next twelve months. As of September 30, 2018 , there were $9.3 million in outstanding letters of credit and $765.0 million outstanding borrowings under our credit facility, leaving approximately $725.7 million available for future borrowing. All other material terms and conditions of our credit facility and outstanding senior unsecured notes are described in Part II, “Item 8. Financial Statements and Supplementary Data—Note 6” in our Annual Report on Form 10-K for the year ended December 31, 2017 .

Partners' Capital

Partners' Capital	9 Months Ended
	Sep. 30, 2018
Partners' Capital Notes [Abstract]
Partners' Capital	(6) Partners' Capital (a) Issuance of Common Units In August 2017, we entered into the 2017 EDA with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program. We may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. We have no obligation to sell any of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA. For the nine months ended September 30, 2018 , we sold an aggregate of approximately 2.6 million common units under the 2017 EDA, generating proceeds of approximately $46.1 million (net of approximately $0.5 million of commissions paid to the Sales Agents). We used the net proceeds for general partnership purposes. As of September 30, 2018 , approximately $518.8 million in aggregate gross proceeds remains available to be issued under the 2017 EDA. (b) 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 . 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 three and nine months ended September 30, 2018 , $24.3 million and $69.0 million of income, respectively, was allocated to the Series B Preferred Units. For the three and nine months ended September 30, 2017 , $22.8 million and $63.6 million of income, respectively, was allocated to the Series B Preferred Units. A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2018 and 2017 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2018 Fourth Quarter of 2017 413,658 $ 16.0 February 13, 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 Third Quarter of 2018 422,720 $ 16.4 November 13, 2018 2017 Fourth Quarter of 2016 1,130,131 $ — February 13, 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 (c) Series C Preferred Units Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15 th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15 th day of March, June, September, and December of each year, in each case, if and when declared by our general partner out of legally available funds for such purpose. The distribution rate for the Series C Preferred Units is 6.0% per annum, and we distributed $12.0 million to holders of Series C Preferred Units during the nine months ended September 30, 2018 . Income is allocated to the Series C Preferred Units in an amount equal to the earned distributions for the respective reporting period. For the three and nine months ended September 30, 2018 , $6.0 million and $18.0 million of income was allocated to the Series C Preferred Units, respectively. For the three and nine months ended September 30, 2017 , $0.7 million of income was allocated to the Series C Preferred Units. (d) Common Unit Distributions Unless restricted by the terms of our credit facility and/or the indentures governing our senior unsecured notes, we must make distributions of 100% of available cash, as defined in our partnership agreement, within 45 days following the end of each quarter. Distributions of available cash are made to our general partner in accordance with its 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 are achieved. The general partner is not entitled to 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. Our general partner owns the general partner interest in us and all incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in the partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled to 13.0% of amounts we distribute in excess of $0.25 per unit, 23.0% of the amounts we distribute in excess of $0.3125 per unit, and 48.0% of amounts we distribute in excess of $0.375 per unit. A summary of the distribution activity relating to the common units during the nine months ended September 30, 2018 and 2017 is provided below: Declaration period Distribution/unit Date paid/payable 2018 Fourth Quarter of 2017 $ 0.39 February 13, 2018 First Quarter of 2018 $ 0.39 May 14, 2018 Second Quarter of 2018 $ 0.39 August 13, 2018 Third Quarter of 2018 $ 0.39 November 13, 2018 2017 Fourth Quarter of 2016 $ 0.39 February 13, 2017 First Quarter of 2017 $ 0.39 May 12, 2017 Second Quarter of 2017 $ 0.39 August 11, 2017 Third Quarter of 2017 $ 0.39 November 13, 2017 (e) 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): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Limited partners’ interest in net income (loss) $ 5.2 $ (8.6 ) $ 85.7 $ (18.4 ) Distributed earnings allocated to: Common units (1)(2) $ 137.3 $ 135.7 $ 410.4 $ 405.0 Unvested restricted units (1)(2) 1.2 1.1 3.1 3.0 Total distributed earnings $ 138.5 $ 136.8 $ 413.5 $ 408.0 Undistributed loss allocated to: Common units $ (132.2 ) $ (144.3 ) $ (325.3 ) $ (423.3 ) Unvested restricted units (1.1 ) (1.1 ) (2.5 ) (3.1 ) Total undistributed loss $ (133.3 ) $ (145.4 ) $ (327.8 ) $ (426.4 ) Net income (loss) allocated to: Common units $ 5.1 $ (8.6 ) $ 85.1 $ (18.3 ) Unvested restricted units 0.1 — 0.6 (0.1 ) Total limited partners’ interest in net income (loss) $ 5.2 $ (8.6 ) $ 85.7 $ (18.4 ) Basic and diluted net income (loss) per unit: Basic $ 0.01 $ (0.02 ) $ 0.24 $ (0.05 ) Diluted $ 0.01 $ (0.02 ) $ 0.24 $ (0.05 ) (1) For the three months ended September 30, 2018 and 2017 , distributed earnings represent a declared distribution of $0.39 per unit payable on November 13, 2018 and a distribution of $0.39 per unit paid on November 13, 2017 , respectively. (2) For the nine months ended September 30, 2018 , distributed earnings included a declared distribution of $0.39 per unit payable on November 13, 2018 , $0.39 per unit paid on August 13, 2018 , and $0.39 per unit paid on May 14, 2018 . For the nine months ended September 30, 2017 , distributed earnings included distributions of $0.39 per unit paid on November 13, 2017 , $0.39 per unit paid on August 11, 2017 , and $0.39 per unit paid on May 12, 2017 . The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding 351.9 347.9 350.7 346.1 Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding 351.9 347.9 350.7 346.1 Dilutive effect of non-vested restricted units (1) 1.6 — 1.5 — Total weighted average limited partner diluted common units outstanding 353.5 347.9 352.2 346.1 (1) All common unit equivalents were antidilutive for the three and nine months ended September 30, 2017 because the limited partners were allocated a net loss. The Series B Preferred Units were also antidilutive for the three and nine months ended September 30, 2018 and 2017 . 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 periods presented. Net income is allocated to our general partner in an amount equal to its incentive distribution rights as described in section “(d) Common Unit Distributions” above. Our general partner’s share of net income consists 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 adjusted for ENLC’s unit-based compensation specifically allocated to our general partner. The net income allocated to our general partner is as follows (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Income allocation for incentive distributions $ 15.0 $ 14.8 $ 44.6 $ 44.1 Unit-based compensation attributable to ENLC’s restricted and performance units (7.3 ) (4.2 ) (15.7 ) (16.9 ) General partner share of net income — — 0.6 0.1 General partner interest in net income $ 7.7 $ 10.6 $ 29.5 $ 27.3

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(7) Investment in Unconsolidated Affiliates As of September 30, 2018 , our unconsolidated investments consisted of a 38.75% ownership in GCF and an approximate 30% ownership in the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 GCF Distributions $ 5.3 $ 3.5 $ 16.4 $ 10.6 Equity in income $ 4.6 $ 4.5 $ 14.0 $ 8.5 HEP Equity in loss (1) $ — $ — $ — $ (3.4 ) Cedar Cove JV Contributions $ — $ 1.5 $ 0.1 $ 11.8 Distributions $ — $ 0.5 $ 0.3 $ 0.8 Equity in loss $ (0.3 ) $ (0.1 ) $ (2.3 ) $ (0.1 ) Total Contributions $ — $ 1.5 $ 0.1 $ 11.8 Distributions $ 5.3 $ 4.0 $ 16.7 $ 11.4 Equity in income (1) $ 4.3 $ 4.4 $ 11.7 $ 5.0 (1) We sold our ownership interest in HEP during the first quarter of 2017 , resulting in a loss of $3.4 million for the nine months ended September 30, 2017 . The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2018 and December 31, 2017 (in millions): September 30, 2018 December 31, 2017 GCF $ 46.0 $ 48.4 Cedar Cove JV 38.5 41.0 Total investment in unconsolidated affiliates $ 84.5 $ 89.4

Employee Incentive Plans

Employee Incentive Plans	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Incentive Plans	(8) Employee Incentive Plans (a) Long-Term Incentive Plans We and ENLC each have similar unit-based compensation payment plans for officers and employees. We grant 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”) . 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 and EOGP. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Cost of unit-based compensation charged to operating expense $ 5.2 $ 2.8 $ 9.5 $ 10.4 Cost of unit-based compensation charged to general and administrative expense 11.8 7.3 22.1 28.3 Total unit-based compensation expense $ 17.0 $ 10.1 $ 31.6 $ 38.7 (b) EnLink Midstream Partners, LP 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 nine months ended September 30, 2018 is provided below: Nine Months Ended 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) 1,586,750 15.27 Vested (1)(2) (813,290 ) 19.78 Forfeited (157,057 ) 12.42 Non-vested, end of period 2,596,627 $ 14.44 Aggregate intrinsic value, end of period (in millions) $ 48.4 (1) Restricted incentive units typically vest at the end of three years. In March 2018, we 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 included 255,653 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, 2018 and 2017 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2018 2017 2018 2017 Aggregate intrinsic value of units vested $ 3.7 $ 0.6 $ 12.8 $ 16.3 Fair value of units vested $ 2.8 $ 1.1 $ 16.1 $ 22.1 As of September 30, 2018 , there was $22.2 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 2.0 years . (c) EnLink Midstream Partners, LP Performance Units Our general partner grants performance awards under the GP 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 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 contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the AMZ, excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLK’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies. 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. 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 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 is 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 Beginning TSR price $ 15.44 Risk-free interest rate 2.38 % Volatility factor 43.85 % Distribution yield 10.5 % The following table presents a summary of the performance units: Nine Months Ended 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) $ 8.4 (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 nine months ended September 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017 . EnLink Midstream Partners, LP Performance Units: Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Aggregate intrinsic value of units vested $ 3.0 $ 5.0 Fair value of units vested $ 3.6 $ 7.7 As of September 30, 2018 , there was $6.2 million of unrecognized compensation cost that related to non-vested ENLK performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years . In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to 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 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 nine months ended September 30, 2018 is provided below: Nine Months Ended 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) 1,469,452 15.76 Vested (1)(2) (749,164 ) 21.53 Forfeited (146,045 ) 12.38 Non-vested, end of period 2,463,553 $ 14.64 Aggregate intrinsic value, end of period (in millions) $ 40.5 (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 included 238,970 units withheld for payroll taxes paid on behalf of employees . A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, 2018 and 2017 is provided below (in millions): Three Months Ended Nine Months Ended EnLink Midstream, LLC Restricted Incentive Units: 2018 2017 2018 2017 Aggregate intrinsic value of units vested $ 3.3 $ 0.6 $ 12.6 $ 15.2 Fair value of units vested $ 2.6 $ 1.1 $ 16.1 $ 21.9 As of September 30, 2018 , there was $21.5 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 2.0 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. 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 Beginning TSR price $ 16.55 Risk-free interest rate 2.38 % Volatility factor 51.36 % Distribution yield 6.7 % The following table presents a summary of the performance units: Nine Months Ended 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) $ 6.9 (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 nine months ended September 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017 . EnLink Midstream, LLC Performance Units: Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Aggregate intrinsic value of units vested $ 2.8 $ 4.7 Fair value of units vested $ 3.5 $ 7.7 As of September 30, 2018 , there was $6.0 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years . In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to 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 c ompensation cost over the life of these ENLC performance units.

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(9) 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 5.45% senior unsecured notes due 2047 (the “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. For the three and nine months ended September 30, 2018 , we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize $0.1 million of interest expense out of accumulated other comprehensive income (loss) over the next twelve months. We have no open interest rate swap position as of September 30, 2018 . 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. They 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 loss on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Change in fair value of derivatives $ (0.8 ) $ (3.3 ) $ (14.8 ) $ 3.8 Realized loss on derivatives (4.6 ) (2.2 ) (5.3 ) (4.9 ) Loss on derivative activity $ (5.4 ) $ (5.5 ) $ (20.1 ) $ (1.1 ) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): September 30, 2018 December 31, 2017 Fair value of derivative assets—current $ 12.5 $ 6.8 Fair value of derivative liabilities—current (21.9 ) (8.4 ) Fair value of derivative liabilities—long-term (7.0 ) — Net fair value of derivatives $ (16.4 ) $ (1.6 ) As of September 30, 2018 and December 31, 2017 , there were no derivative assets classified as long-term on the consolidated balance sheets. 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 September 30, 2018 (in millions). The remaining term of the contracts extend no later than December 2022. September 30, 2018 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (58.4 ) $ (12.0 ) NGL (long contracts) Swaps Gallons 18.9 3.1 Natural Gas (short contracts) Swaps MMBtu (9.0 ) 0.4 Natural Gas (long contracts) Swaps MMBtu 10.9 (1.4 ) Crude and condensate (short contracts) Swaps MMbbls (13.3 ) (13.2 ) Crude and condensate (long contracts) Swaps MMbbls 1.3 6.7 Total fair value of derivatives $ (16.4 ) On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing swap contracts, the maximum loss on our gross receivable position of $12.5 million as of September 30, 2018 would be reduced to $0.1 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	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	(10) 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 September 30, 2018 December 31, 2017 Commodity Swaps (1) $ (16.4 ) $ (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): September 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Fair Long-term debt, including current maturities of long-term debt (1) $ 4,235.5 $ 4,017.6 $ 3,467.8 $ 3,575.6 Installment Payables $ — $ — $ 249.5 $ 249.6 Obligations under capital lease $ 2.9 $ 2.5 $ 4.1 $ 3.4 Secured term loan receivable $ 49.9 $ 49.9 $ — $ — (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of $23.4 million and $25.9 million at September 30, 2018 and December 31, 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. We had $765.0 million of outstanding borrowings under our credit facility as of September 30, 2018 and no outstanding borrowings under our credit facility as of December 31, 2017 . As borrowings under our credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under our credit facility. As of September 30, 2018 and December 31, 2017 , we had total borrowings under senior unsecured notes of $3.5 billion 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 September 30, 2018 and December 31, 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.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information	(11) Segment Information Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist 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. 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 three and nine months ended September 30, 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 Three Months Ended September 30, 2018 Natural gas sales $ 69.1 $ 129.5 $ 41.9 $ — $ — $ 240.5 NGL sales 16.8 839.6 12.8 0.1 — 869.3 Crude oil and condensate sales — 0.1 0.3 722.0 — 722.4 Product sales 85.9 969.2 55.0 722.1 — 1,832.2 Natural gas sales—related parties — — 0.1 — — 0.1 NGL sales—related parties 153.8 10.9 192.5 — (347.2 ) 10.0 Crude oil and condensate sales—related parties 13.4 0.1 18.0 1.5 (32.9 ) 0.1 Product sales—related parties 167.2 11.0 210.6 1.5 (380.1 ) 10.2 Gathering and transportation 71.7 17.5 50.2 0.8 — 140.2 Processing 39.4 0.8 31.5 — — 71.7 NGL services — 11.9 — — — 11.9 Crude services — — 0.2 14.9 — 15.1 Other services 2.4 0.1 — 0.1 — 2.6 Midstream services 113.5 30.3 81.9 15.8 — 241.5 Gathering and transportation—related parties 8.7 — 7.2 — — 15.9 Processing—related parties 10.2 — 3.2 — — 13.4 Crude services—related parties — — 0.1 6.3 — 6.4 Other services—related parties 0.1 — — — — 0.1 Midstream services—related parties 19.0 — 10.5 6.3 — 35.8 Revenue from contracts with customers 385.6 1,010.5 358.0 745.7 (380.1 ) 2,119.7 Cost of sales (222.0 ) (923.6 ) (228.5 ) (702.6 ) 380.1 (1,696.6 ) Operating expenses (44.7 ) (28.7 ) (22.5 ) (18.8 ) — (114.7 ) Loss on derivative activity — — — — (5.4 ) (5.4 ) Segment profit (loss) $ 118.9 $ 58.2 $ 107.0 $ 24.3 $ (5.4 ) $ 303.0 Depreciation and amortization $ (54.0 ) $ (32.7 ) $ (44.7 ) $ (12.9 ) $ (2.4 ) $ (146.7 ) Impairments $ — $ (24.6 ) $ — $ — $ — $ (24.6 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 90.0 $ 13.0 $ 109.3 $ 39.9 $ 1.1 $ 253.3 Three Months Ended September 30, 2017 Product sales $ 80.8 $ 642.3 $ 42.5 $ 291.1 $ — $ 1,056.7 Product sales—related parties 130.6 10.0 94.6 — (199.9 ) 35.3 Midstream services 29.1 50.3 44.3 12.7 — 136.4 Midstream services—related parties 106.7 35.9 63.0 4.8 (35.4 ) 175.0 Cost of sales (198.5 ) (662.7 ) (148.2 ) (279.1 ) 235.3 (1,053.2 ) Operating expenses (41.1 ) (24.8 ) (17.1 ) (19.1 ) — (102.1 ) Loss on derivative activity — — — — (5.5 ) (5.5 ) Segment profit (loss) $ 107.6 $ 51.0 $ 79.1 $ 10.4 $ (5.5 ) $ 242.6 Depreciation and amortization $ (52.5 ) $ (29.3 ) $ (40.2 ) $ (11.7 ) $ (2.6 ) $ (136.3 ) Impairments $ — $ — $ — $ (1.8 ) $ — $ (1.8 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 39.1 $ 7.5 $ 107.7 $ 13.3 $ 2.1 $ 169.7 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Nine Months Ended September 30, 2018 Natural gas sales $ 208.9 $ 377.2 $ 127.9 $ — $ — $ 714.0 NGL sales 16.8 2,075.9 18.3 0.9 — 2,111.9 Crude oil and condensate sales — 0.2 0.3 1,940.1 — 1,940.6 Product sales 225.7 2,453.3 146.5 1,941.0 — 4,766.5 Natural gas sales—related parties — — 2.5 — — 2.5 NGL sales—related parties 381.1 45.4 433.0 — (822.1 ) 37.4 Crude oil and condensate sales—related parties 39.4 0.3 63.9 3.3 (105.8 ) 1.1 Product sales—related parties 420.5 45.7 499.4 3.3 (927.9 ) 41.0 Gathering and transportation 98.4 51.8 91.4 2.5 — 244.1 Processing 52.7 2.5 87.9 — — 143.1 NGL services — 38.8 — — — 38.8 Crude services — — 0.2 42.8 — 43.0 Other services 6.4 0.5 — 0.2 — 7.1 Midstream services 157.5 93.6 179.5 45.5 — 476.1 Gathering and transportation—related parties 122.7 — 80.6 — — 203.3 Processing—related parties 108.6 — 48.4 — — 157.0 Crude services—related parties — — 1.5 14.9 — 16.4 Other services—related parties 0.5 — — — — 0.5 Midstream services—related parties 231.8 — 130.5 14.9 — 377.2 Revenue from contracts with customers 1,035.5 2,592.6 955.9 2,004.7 (927.9 ) 5,660.8 Cost of sales (562.2 ) (2,333.3 ) (537.8 ) (1,898.3 ) 927.9 (4,403.7 ) Operating expenses (134.7 ) (82.3 ) (64.0 ) (56.3 ) — (337.3 ) Loss on derivative activity — — — — (20.1 ) (20.1 ) Segment profit (loss) $ 338.6 $ 177.0 $ 354.1 $ 50.1 $ (20.1 ) $ 899.7 Depreciation and amortization $ (159.9 ) $ (92.4 ) $ (133.2 ) $ (38.0 ) $ (6.6 ) $ (430.1 ) Impairments $ — $ (24.6 ) $ — $ — $ — $ (24.6 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 200.0 $ 36.4 $ 328.8 $ 84.1 $ 3.4 $ 652.7 Nine Months Ended September 30, 2017 Product sales $ 240.5 $ 1,735.5 $ 84.7 $ 913.2 $ — $ 2,973.9 Product sales—related parties 352.6 25.6 221.4 0.8 (493.1 ) 107.3 Midstream services 85.1 159.7 105.2 45.7 — 395.7 Midstream services—related parties 319.0 100.2 171.8 13.4 (96.8 ) 507.6 Cost of sales (554.7 ) (1,803.1 ) (335.9 ) (884.1 ) 589.9 (2,987.9 ) Operating expenses (127.9 ) (74.8 ) (45.9 ) (60.2 ) — (308.8 ) Loss on derivative activity — — — — (1.1 ) (1.1 ) Segment profit (loss) $ 314.6 $ 143.1 $ 201.3 $ 28.8 $ (1.1 ) $ 686.7 Depreciation and amortization $ (161.9 ) $ (86.8 ) $ (115.3 ) $ (35.8 ) $ (7.3 ) $ (407.1 ) Impairments $ — $ — $ — $ (8.8 ) $ — $ (8.8 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 107.1 $ 55.8 $ 383.4 $ 64.4 $ 25.6 $ 636.3 The table below represents information about segment assets as of September 30, 2018 and December 31, 2017 (in millions): Segment Identifiable Assets: September 30, 2018 December 31, 2017 Texas $ 3,161.9 $ 3,094.8 Louisiana 2,583.8 2,408.5 Oklahoma 3,074.1 2,836.7 Crude and Condensate 1,069.9 929.5 Corporate 183.9 144.5 Total identifiable assets $ 10,073.6 $ 9,414.0 The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Segment profit $ 303.0 $ 242.6 $ 899.7 $ 686.7 General and administrative expenses (39.2 ) (30.0 ) (94.5 ) (94.6 ) Loss on disposition of assets — (1.1 ) (1.3 ) (0.8 ) Depreciation and amortization (146.7 ) (136.3 ) (430.1 ) (407.1 ) Impairments (24.6 ) (1.8 ) (24.6 ) (8.8 ) Gain on litigation settlement — — — 26.0 Operating income $ 92.5 $ 73.4 $ 349.2 $ 201.4

Other Information

Other Information	9 Months Ended
	Sep. 30, 2018
Other Liabilities Disclosure [Abstract]
Other Information	(12) 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: September 30, 2018 December 31, 2017 Natural gas and NGLs inventory $ 119.4 $ 30.1 Secured term loan receivable from contract restructuring, net of discount o f $1.1 18.4 — Prepaid expenses and other 15.6 9.6 Natural gas and NGLs inventory, prepaid expenses, and other $ 153.4 $ 39.7 Other Current Liabilities: September 30, 2018 December 31, 2017 Accrued interest $ 64.5 $ 35.4 Accrued wages and benefits, including taxes 24.8 30.4 Accrued ad valorem taxes 33.4 27.8 Capital expenditure accruals 57.9 48.8 Onerous performance obligations 13.5 15.2 Other 65.7 64.8 Other current liabilities $ 259.8 $ 222.4

Subsequent Event

Subsequent Event	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Event	(13) Subsequent Event On October 21, 2018, we and ENLC entered into the Merger Agreement and the related preferred restructuring agreement, pursuant to which, subject to the satisfaction or waiver of certain conditions: • Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) will be converted into the right to receive 1.15 ENLC common units; • Our general partner’s incentive distribution rights in ENLK will be 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 will be modified pursuant to an amended partnership agreement of ENLK, including exchangeability of the Series B Preferred Units, under certain circumstances, into ENLC common units instead of ENLK common units, subject to the election of ENLK to instead redeem for cash any such exchanged Series B Preferred Units; • ENLC will issue to Enfield Holdings, L.P. (“Enfield”), the current holder of the Series B Preferred Units, for no additional consideration, a new class of non-economic ENLC 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; • The Series C Preferred Units will continue to be issued and outstanding following the Merger; and • All unit-based awards issued and outstanding immediately prior to the effective time of the Merger under the GP Plan will be 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. The Merger Transactions are expected to close in the first quarter of 2019, subject to obtaining approval of our unitholders, customary regulatory approvals, and other customary closing conditions.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.
Revenue Recognition	Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales —Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services —Midstream services represent all other revenue generated as a result of performing our midstream services as 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 three and nine months ended September 30, 2018 , the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $179 million and $480 million , respectively, or 8% and 8% , respectively, 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 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Product sales $ (71 ) $ (149 ) Product sales—related parties (7 ) (53 ) Midstream services (98 ) (251 ) Midstream services—related parties (3 ) (27 ) Total $ (179 ) $ (480 ) 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. 2018 (remaining) $ 190.9 2019 237.1 2020 225.7 2021 82.3 2022 71.9 Thereafter 231.2 Total $ 1,039.1 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 three and nine months ended September 30, 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 11—Segment Information for the revenue disaggregation information included in the segment information table for the three and nine months ended September 30, 2018 . As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the three and nine months ended September 30, 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.
Accounting Standards to be Adopted in Future Periods	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 are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. 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. While we are still evaluating the complete population of lease contracts, we believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by less than $100 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.
Property and Equipment	Property & Equipment Impairment Review. In accordance with ASC 360, Property, Plant and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets 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 loss is recognized equal to the excess of the asset’s carrying value over its fair value.
Derivatives	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.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2018 , the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $179 million and $480 million , respectively, or 8% and 8% , respectively, 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 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Product sales $ (71 ) $ (149 ) Product sales—related parties (7 ) (53 ) Midstream services (98 ) (251 ) Midstream services—related parties (3 ) (27 ) Total $ (179 ) $ (480 )
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. 2018 (remaining) $ 190.9 2019 237.1 2020 225.7 2021 82.3 2022 71.9 Thereafter 231.2 Total $ 1,039.1

Intangible Assets (Tables)

Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Change in Carrying Value	The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Nine Months Ended September 30, 2018 Customer relationships, beginning of period $ 1,795.8 $ (298.7 ) $ 1,497.1 Amortization expense — (92.6 ) (92.6 ) Customer relationships, end of period $ 1,795.8 $ (391.3 ) $ 1,404.5
Summary of Estimated Aggregate Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2018 (remaining) $ 30.9 2019 123.7 2020 123.7 2021 123.7 2022 123.7 Thereafter 878.8 Total $ 1,404.5

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As of September 30, 2018 and December 31, 2017 , long-term debt consisted of the following (in millions): September 30, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Credit facility due 2020 (1) $ 765.0 $ — $ 765.0 $ — $ — $ — 2.70% Senior unsecured notes due 2019 (2) 400.0 (0.1 ) 399.9 400.0 (0.1 ) 399.9 4.40% Senior unsecured notes due 2024 550.0 1.9 551.9 550.0 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, including current maturities of long-term debt $ 4,265.0 $ (6.1 ) 4,258.9 $ 3,500.0 $ (6.3 ) 3,493.7 Debt issuance cost (3) (23.4 ) (25.9 ) Less: Current maturities of long-term debt (2) (399.6 ) — Long-term debt, net of unamortized issuance cost $ 3,835.9 $ 3,467.8 (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.1% at September 30, 2018 . (2) 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 September 30, 2018 . (3) Net of amortization of $14.5 million and $12.0 million at September 30, 2018 and December 31, 2017 , respectively.

Partners' Capital (Tables)

Partners' Capital (Tables)	9 Months Ended
	Sep. 30, 2018
Partners' Capital Notes [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2018 and 2017 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2018 Fourth Quarter of 2017 413,658 $ 16.0 February 13, 2018 First Quarter of 2018 416,657 $ 16.2 May 14, 2018 Second Quarter of 2018 419,678 $ 16.3 August 13, 2018 Third Quarter of 2018 422,720 $ 16.4 November 13, 2018 2017 Fourth Quarter of 2016 1,130,131 $ — February 13, 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 A summary of the distribution activity relating to the common units during the nine months ended September 30, 2018 and 2017 is provided below: Declaration period Distribution/unit Date paid/payable 2018 Fourth Quarter of 2017 $ 0.39 February 13, 2018 First Quarter of 2018 $ 0.39 May 14, 2018 Second Quarter of 2018 $ 0.39 August 13, 2018 Third Quarter of 2018 $ 0.39 November 13, 2018 2017 Fourth Quarter of 2016 $ 0.39 February 13, 2017 First Quarter of 2017 $ 0.39 May 12, 2017 Second Quarter of 2017 $ 0.39 August 11, 2017 Third Quarter of 2017 $ 0.39 November 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): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Limited partners’ interest in net income (loss) $ 5.2 $ (8.6 ) $ 85.7 $ (18.4 ) Distributed earnings allocated to: Common units (1)(2) $ 137.3 $ 135.7 $ 410.4 $ 405.0 Unvested restricted units (1)(2) 1.2 1.1 3.1 3.0 Total distributed earnings $ 138.5 $ 136.8 $ 413.5 $ 408.0 Undistributed loss allocated to: Common units $ (132.2 ) $ (144.3 ) $ (325.3 ) $ (423.3 ) Unvested restricted units (1.1 ) (1.1 ) (2.5 ) (3.1 ) Total undistributed loss $ (133.3 ) $ (145.4 ) $ (327.8 ) $ (426.4 ) Net income (loss) allocated to: Common units $ 5.1 $ (8.6 ) $ 85.1 $ (18.3 ) Unvested restricted units 0.1 — 0.6 (0.1 ) Total limited partners’ interest in net income (loss) $ 5.2 $ (8.6 ) $ 85.7 $ (18.4 ) Basic and diluted net income (loss) per unit: Basic $ 0.01 $ (0.02 ) $ 0.24 $ (0.05 ) Diluted $ 0.01 $ (0.02 ) $ 0.24 $ (0.05 ) (1) For the three months ended September 30, 2018 and 2017 , distributed earnings represent a declared distribution of $0.39 per unit payable on November 13, 2018 and a distribution of $0.39 per unit paid on November 13, 2017 , respectively. (2) For the nine months ended September 30, 2018 , distributed earnings included a declared distribution of $0.39 per unit payable on November 13, 2018 , $0.39 per unit paid on August 13, 2018 , and $0.39 per unit paid on May 14, 2018 . For the nine months ended September 30, 2017 , distributed earnings included distributions of $0.39 per unit paid on November 13, 2017 , $0.39 per unit paid on August 11, 2017 , and $0.39 per unit paid on May 12, 2017 .
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 unit for the periods presented (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding 351.9 347.9 350.7 346.1 Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding 351.9 347.9 350.7 346.1 Dilutive effect of non-vested restricted units (1) 1.6 — 1.5 — Total weighted average limited partner diluted common units outstanding 353.5 347.9 352.2 346.1 (1) All common unit equivalents were antidilutive for the three and nine months ended September 30, 2017 because the limited partners were allocated a net loss. The Series B Preferred Units were also antidilutive for the three and nine months ended September 30, 2018 and 2017 .
Incentive Distributions	The net income allocated to our general partner is as follows (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Income allocation for incentive distributions $ 15.0 $ 14.8 $ 44.6 $ 44.1 Unit-based compensation attributable to ENLC’s restricted and performance units (7.3 ) (4.2 ) (15.7 ) (16.9 ) General partner share of net income — — 0.6 0.1 General partner interest in net income $ 7.7 $ 10.6 $ 29.5 $ 27.3

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
Summary of Activity and Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 GCF Distributions $ 5.3 $ 3.5 $ 16.4 $ 10.6 Equity in income $ 4.6 $ 4.5 $ 14.0 $ 8.5 HEP Equity in loss (1) $ — $ — $ — $ (3.4 ) Cedar Cove JV Contributions $ — $ 1.5 $ 0.1 $ 11.8 Distributions $ — $ 0.5 $ 0.3 $ 0.8 Equity in loss $ (0.3 ) $ (0.1 ) $ (2.3 ) $ (0.1 ) Total Contributions $ — $ 1.5 $ 0.1 $ 11.8 Distributions $ 5.3 $ 4.0 $ 16.7 $ 11.4 Equity in income (1) $ 4.3 $ 4.4 $ 11.7 $ 5.0 (1) We sold our ownership interest in HEP during the first quarter of 2017 , resulting in a loss of $3.4 million for the nine months ended September 30, 2017 . The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2018 and December 31, 2017 (in millions): September 30, 2018 December 31, 2017 GCF $ 46.0 $ 48.4 Cedar Cove JV 38.5 41.0 Total investment in unconsolidated affiliates $ 84.5 $ 89.4

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 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): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Cost of unit-based compensation charged to operating expense $ 5.2 $ 2.8 $ 9.5 $ 10.4 Cost of unit-based compensation charged to general and administrative expense 11.8 7.3 22.1 28.3 Total unit-based compensation expense $ 17.0 $ 10.1 $ 31.6 $ 38.7
Summary of Restricted Incentive Unit Activity	A summary of the restricted incentive unit activity for the nine months ended September 30, 2018 is provided below: Nine Months Ended 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) 1,586,750 15.27 Vested (1)(2) (813,290 ) 19.78 Forfeited (157,057 ) 12.42 Non-vested, end of period 2,596,627 $ 14.44 Aggregate intrinsic value, end of period (in millions) $ 48.4 (1) Restricted incentive units typically vest at the end of three years. In March 2018, we 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 included 255,653 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive unit activity for the nine months ended September 30, 2018 is provided below: Nine Months Ended 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) 1,469,452 15.76 Vested (1)(2) (749,164 ) 21.53 Forfeited (146,045 ) 12.38 Non-vested, end of period 2,463,553 $ 14.64 Aggregate intrinsic value, end of period (in millions) $ 40.5 (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 included 238,970 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) for the three and nine months ended September 30, 2018 and 2017 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2018 2017 2018 2017 Aggregate intrinsic value of units vested $ 3.7 $ 0.6 $ 12.8 $ 16.3 Fair value of units vested $ 2.8 $ 1.1 $ 16.1 $ 22.1 A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, 2018 and 2017 is provided below (in millions): Three Months Ended Nine Months Ended EnLink Midstream, LLC Restricted Incentive Units: 2018 2017 2018 2017 Aggregate intrinsic value of units vested $ 3.3 $ 0.6 $ 12.6 $ 15.2 Fair value of units vested $ 2.6 $ 1.1 $ 16.1 $ 21.9
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 Beginning TSR price $ 15.44 Risk-free interest rate 2.38 % Volatility factor 43.85 % Distribution yield 10.5 % 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 Beginning TSR price $ 16.55 Risk-free interest rate 2.38 % Volatility factor 51.36 % Distribution yield 6.7 %
Summary of Performance Units	The following table presents a summary of the performance units: Nine Months Ended 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) $ 8.4 (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 nine months ended September 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017 . EnLink Midstream Partners, LP Performance Units: Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Aggregate intrinsic value of units vested $ 3.0 $ 5.0 Fair value of units vested $ 3.6 $ 7.7 The following table presents a summary of the performance units: Nine Months Ended 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) $ 6.9 (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 nine months ended September 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017 . EnLink Midstream, LLC Performance Units: Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Aggregate intrinsic value of units vested $ 2.8 $ 4.7 Fair value of units vested $ 3.5 $ 7.7

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss)	The components of loss on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Change in fair value of derivatives $ (0.8 ) $ (3.3 ) $ (14.8 ) $ 3.8 Realized loss on derivatives (4.6 ) (2.2 ) (5.3 ) (4.9 ) Loss on derivative activity $ (5.4 ) $ (5.5 ) $ (20.1 ) $ (1.1 )
Fair Value of Derivative Assets and Liabilities	The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): September 30, 2018 December 31, 2017 Fair value of derivative assets—current $ 12.5 $ 6.8 Fair value of derivative liabilities—current (21.9 ) (8.4 ) Fair value of derivative liabilities—long-term (7.0 ) — Net fair value of derivatives $ (16.4 ) $ (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 September 30, 2018 (in millions). The remaining term of the contracts extend no later than December 2022. September 30, 2018 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (58.4 ) $ (12.0 ) NGL (long contracts) Swaps Gallons 18.9 3.1 Natural Gas (short contracts) Swaps MMBtu (9.0 ) 0.4 Natural Gas (long contracts) Swaps MMBtu 10.9 (1.4 ) Crude and condensate (short contracts) Swaps MMbbls (13.3 ) (13.2 ) Crude and condensate (long contracts) Swaps MMbbls 1.3 6.7 Total fair value of derivatives $ (16.4 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2018 December 31, 2017 Commodity Swaps (1) $ (16.4 ) $ (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): September 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Fair Long-term debt, including current maturities of long-term debt (1) $ 4,235.5 $ 4,017.6 $ 3,467.8 $ 3,575.6 Installment Payables $ — $ — $ 249.5 $ 249.6 Obligations under capital lease $ 2.9 $ 2.5 $ 4.1 $ 3.4 Secured term loan receivable $ 49.9 $ 49.9 $ — $ — (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of $23.4 million and $25.9 million at September 30, 2018 and December 31, 2017 , respectively. The respective fair values do not factor in debt issuance costs.

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 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 Three Months Ended September 30, 2018 Natural gas sales $ 69.1 $ 129.5 $ 41.9 $ — $ — $ 240.5 NGL sales 16.8 839.6 12.8 0.1 — 869.3 Crude oil and condensate sales — 0.1 0.3 722.0 — 722.4 Product sales 85.9 969.2 55.0 722.1 — 1,832.2 Natural gas sales—related parties — — 0.1 — — 0.1 NGL sales—related parties 153.8 10.9 192.5 — (347.2 ) 10.0 Crude oil and condensate sales—related parties 13.4 0.1 18.0 1.5 (32.9 ) 0.1 Product sales—related parties 167.2 11.0 210.6 1.5 (380.1 ) 10.2 Gathering and transportation 71.7 17.5 50.2 0.8 — 140.2 Processing 39.4 0.8 31.5 — — 71.7 NGL services — 11.9 — — — 11.9 Crude services — — 0.2 14.9 — 15.1 Other services 2.4 0.1 — 0.1 — 2.6 Midstream services 113.5 30.3 81.9 15.8 — 241.5 Gathering and transportation—related parties 8.7 — 7.2 — — 15.9 Processing—related parties 10.2 — 3.2 — — 13.4 Crude services—related parties — — 0.1 6.3 — 6.4 Other services—related parties 0.1 — — — — 0.1 Midstream services—related parties 19.0 — 10.5 6.3 — 35.8 Revenue from contracts with customers 385.6 1,010.5 358.0 745.7 (380.1 ) 2,119.7 Cost of sales (222.0 ) (923.6 ) (228.5 ) (702.6 ) 380.1 (1,696.6 ) Operating expenses (44.7 ) (28.7 ) (22.5 ) (18.8 ) — (114.7 ) Loss on derivative activity — — — — (5.4 ) (5.4 ) Segment profit (loss) $ 118.9 $ 58.2 $ 107.0 $ 24.3 $ (5.4 ) $ 303.0 Depreciation and amortization $ (54.0 ) $ (32.7 ) $ (44.7 ) $ (12.9 ) $ (2.4 ) $ (146.7 ) Impairments $ — $ (24.6 ) $ — $ — $ — $ (24.6 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 90.0 $ 13.0 $ 109.3 $ 39.9 $ 1.1 $ 253.3 Three Months Ended September 30, 2017 Product sales $ 80.8 $ 642.3 $ 42.5 $ 291.1 $ — $ 1,056.7 Product sales—related parties 130.6 10.0 94.6 — (199.9 ) 35.3 Midstream services 29.1 50.3 44.3 12.7 — 136.4 Midstream services—related parties 106.7 35.9 63.0 4.8 (35.4 ) 175.0 Cost of sales (198.5 ) (662.7 ) (148.2 ) (279.1 ) 235.3 (1,053.2 ) Operating expenses (41.1 ) (24.8 ) (17.1 ) (19.1 ) — (102.1 ) Loss on derivative activity — — — — (5.5 ) (5.5 ) Segment profit (loss) $ 107.6 $ 51.0 $ 79.1 $ 10.4 $ (5.5 ) $ 242.6 Depreciation and amortization $ (52.5 ) $ (29.3 ) $ (40.2 ) $ (11.7 ) $ (2.6 ) $ (136.3 ) Impairments $ — $ — $ — $ (1.8 ) $ — $ (1.8 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 39.1 $ 7.5 $ 107.7 $ 13.3 $ 2.1 $ 169.7 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals Nine Months Ended September 30, 2018 Natural gas sales $ 208.9 $ 377.2 $ 127.9 $ — $ — $ 714.0 NGL sales 16.8 2,075.9 18.3 0.9 — 2,111.9 Crude oil and condensate sales — 0.2 0.3 1,940.1 — 1,940.6 Product sales 225.7 2,453.3 146.5 1,941.0 — 4,766.5 Natural gas sales—related parties — — 2.5 — — 2.5 NGL sales—related parties 381.1 45.4 433.0 — (822.1 ) 37.4 Crude oil and condensate sales—related parties 39.4 0.3 63.9 3.3 (105.8 ) 1.1 Product sales—related parties 420.5 45.7 499.4 3.3 (927.9 ) 41.0 Gathering and transportation 98.4 51.8 91.4 2.5 — 244.1 Processing 52.7 2.5 87.9 — — 143.1 NGL services — 38.8 — — — 38.8 Crude services — — 0.2 42.8 — 43.0 Other services 6.4 0.5 — 0.2 — 7.1 Midstream services 157.5 93.6 179.5 45.5 — 476.1 Gathering and transportation—related parties 122.7 — 80.6 — — 203.3 Processing—related parties 108.6 — 48.4 — — 157.0 Crude services—related parties — — 1.5 14.9 — 16.4 Other services—related parties 0.5 — — — — 0.5 Midstream services—related parties 231.8 — 130.5 14.9 — 377.2 Revenue from contracts with customers 1,035.5 2,592.6 955.9 2,004.7 (927.9 ) 5,660.8 Cost of sales (562.2 ) (2,333.3 ) (537.8 ) (1,898.3 ) 927.9 (4,403.7 ) Operating expenses (134.7 ) (82.3 ) (64.0 ) (56.3 ) — (337.3 ) Loss on derivative activity — — — — (20.1 ) (20.1 ) Segment profit (loss) $ 338.6 $ 177.0 $ 354.1 $ 50.1 $ (20.1 ) $ 899.7 Depreciation and amortization $ (159.9 ) $ (92.4 ) $ (133.2 ) $ (38.0 ) $ (6.6 ) $ (430.1 ) Impairments $ — $ (24.6 ) $ — $ — $ — $ (24.6 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 200.0 $ 36.4 $ 328.8 $ 84.1 $ 3.4 $ 652.7 Nine Months Ended September 30, 2017 Product sales $ 240.5 $ 1,735.5 $ 84.7 $ 913.2 $ — $ 2,973.9 Product sales—related parties 352.6 25.6 221.4 0.8 (493.1 ) 107.3 Midstream services 85.1 159.7 105.2 45.7 — 395.7 Midstream services—related parties 319.0 100.2 171.8 13.4 (96.8 ) 507.6 Cost of sales (554.7 ) (1,803.1 ) (335.9 ) (884.1 ) 589.9 (2,987.9 ) Operating expenses (127.9 ) (74.8 ) (45.9 ) (60.2 ) — (308.8 ) Loss on derivative activity — — — — (1.1 ) (1.1 ) Segment profit (loss) $ 314.6 $ 143.1 $ 201.3 $ 28.8 $ (1.1 ) $ 686.7 Depreciation and amortization $ (161.9 ) $ (86.8 ) $ (115.3 ) $ (35.8 ) $ (7.3 ) $ (407.1 ) Impairments $ — $ — $ — $ (8.8 ) $ — $ (8.8 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ — $ 422.3 Capital expenditures $ 107.1 $ 55.8 $ 383.4 $ 64.4 $ 25.6 $ 636.3
Schedule of Assets	The table below represents information about segment assets as of September 30, 2018 and December 31, 2017 (in millions): Segment Identifiable Assets: September 30, 2018 December 31, 2017 Texas $ 3,161.9 $ 3,094.8 Louisiana 2,583.8 2,408.5 Oklahoma 3,074.1 2,836.7 Crude and Condensate 1,069.9 929.5 Corporate 183.9 144.5 Total identifiable assets $ 10,073.6 $ 9,414.0
Reconciliation of Profits Reported to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Segment profit $ 303.0 $ 242.6 $ 899.7 $ 686.7 General and administrative expenses (39.2 ) (30.0 ) (94.5 ) (94.6 ) Loss on disposition of assets — (1.1 ) (1.3 ) (0.8 ) Depreciation and amortization (146.7 ) (136.3 ) (430.1 ) (407.1 ) Impairments (24.6 ) (1.8 ) (24.6 ) (8.8 ) Gain on litigation settlement — — — 26.0 Operating income $ 92.5 $ 73.4 $ 349.2 $ 201.4

Other Information (Tables)

Other Information (Tables)	9 Months Ended
	Sep. 30, 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: September 30, 2018 December 31, 2017 Natural gas and NGLs inventory $ 119.4 $ 30.1 Secured term loan receivable from contract restructuring, net of discount o f $1.1 18.4 — Prepaid expenses and other 15.6 9.6 Natural gas and NGLs inventory, prepaid expenses, and other $ 153.4 $ 39.7 Other Current Liabilities: September 30, 2018 December 31, 2017 Accrued interest $ 64.5 $ 35.4 Accrued wages and benefits, including taxes 24.8 30.4 Accrued ad valorem taxes 33.4 27.8 Capital expenditure accruals 57.9 48.8 Onerous performance obligations 13.5 15.2 Other 65.7 64.8 Other current liabilities $ 259.8 $ 222.4

General (Details)

General (Details)	Jul. 18, 2018
GIP Stetson I | EnLink Midstream Partners GP, LLC
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests	100.00%
GIP Stetson I | EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests	23.10%
GIP Stetson II | ENLC
Business Acquisition [Line Items]
Percentage of outstanding limited liability company interests	63.80%

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended			9 Months Ended
	May 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Jan. 01, 2019
Property, Plant and Equipment [Line Items]
Decrease in revenue from contracts with customers		$ (2,119,700,000)			$ (5,660,800,000)
Expected gross operating margin from long-term purchase commitment	$ 135,100,000
Amount received from counterparty due to deficiency on MVC	19,700,000
Total principal payments to be received	$ 58,000,000
Financing receivable, interest rate	8.00%
Overriding royalty interest percentage	1.00%
Consideration received due to restructuring of contract			$ 45,500,000
Expired rights-of-ways and abandoned brine disposal well
Property, Plant and Equipment [Line Items]
Impaired assets		24,600,000		$ 1,800,000	24,600,000	$ 8,800,000
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Property, Plant and Equipment [Line Items]
Decrease in revenue from contracts with customers		$ 179,000,000			$ 480,000,000
Percentage decrease in revenue from contract with customers		8.00%			8.00%
Scenario, Forecast | Accounting Standards Update 2016-02
Property, Plant and Equipment [Line Items]
Right-of-use asset (less than)							$ 100,000,000
Lease liability (less than)							$ 100,000,000

Significant Accounting Polici_5

Significant Accounting Policies - Summary of Changes in Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	$ 2,119.7		$ 5,660.8
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	(179)		(480)
Product sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	1,832.2	$ 1,056.7	4,766.5	$ 2,973.9
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	(71)		(149)
Product sales—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	10.2	35.3	41	107.3
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	(7)		(53)
Midstream services
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	241.5	136.4	476.1	395.7
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	(98)		(251)
Midstream services—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	35.8	$ 175	377.2	$ 507.6
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	$ (3)		$ (27)

Significant Accounting Polici_6

Significant Accounting Policies - Summary of Expected Future Performance Obligations (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Accounting Policies [Abstract]
Expected gross operating margin	$ 1,039.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 190.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 237.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 225.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 82.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 71.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Expected gross operating margin	$ 231.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Goodwill
Amortization expense	$ 30.9	$ 31.2	$ 92.6	$ 96.2
Minimum
Goodwill
Amortization period			5 years
Maximum
Goodwill
Amortization period			20 years
Weighted average
Goodwill
Amortization period			15 years

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning balance			$ (298.7)
Accumulated Amortization, Amortization expense	$ (30.9)	$ (31.2)	(92.6)	$ (96.2)
Accumulated Amortization, Ending balance	(391.3)		(391.3)
Net Carrying Amount, Ending balance	1,404.5		1,404.5
Customer relationships
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning balance			1,795.8
Accumulated Amortization, Beginning balance			(298.7)
Net Carrying Amount, Beginning balance			1,497.1
Accumulated Amortization, Amortization expense			(92.6)
Gross Carrying Amount, Ending balance	1,795.8		1,795.8
Accumulated Amortization, Ending balance	(391.3)		(391.3)
Net Carrying Amount, Ending balance	$ 1,404.5		$ 1,404.5

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) $ in Millions	Sep. 30, 2018USD ($)
Summary of estimated amortization expense
2018 (remaining)	$ 30.9
2,019	123.7
2,020	123.7
2,021	123.7
2,022	123.7
Thereafter	878.8
Total	$ 1,404.5

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		7 Months Ended	9 Months Ended
		Jul. 18, 2018	Sep. 30, 2018	Sep. 30, 2017	Jul. 18, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction
Accounts payable to related party			$ 5			$ 5		$ 18.4
Cost of sales	[1]		1,696.6	$ 1,053.2		4,403.7	$ 2,987.9
Devon
Related Party Transaction
Accounts receivable balance								102.7
Accounts payable to related party								$ 16.3
Sales Revenue, Net | Customer Concentration Risk | Devon
Related Party Transaction
Concentration risk		7.30%		15.00%	2.00%		15.40%
Cedar Cove Joint Venture
Related Party Transaction
Accounts receivable balance			0.7			0.7
Accounts payable to related party			5			5
Cost of sales			$ 11.3	$ 9.5		$ 33.8	$ 15
[1]	Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	May 31, 2017
Debt Instrument
Outstanding Principal	$ 4,265	$ 3,500
Premium (Discount)	(6.1)	(6.3)
Long-Term Debt	4,258.9	3,493.7
Debt issuance costs	(23.4)	(25.9)
Less: Current maturities of long-term debt	(399.6)	0
Long-term debt, net of unamortized issuance cost	$ 3,835.9	3,467.8
Effective interest rate	4.10%
Amortization	$ 14.5	12
Credit facility due 2020
Debt Instrument
Outstanding Principal	765	0
Premium (Discount)	0	0
Long-Term Debt	$ 765	0
2.70% Senior unsecured notes due 2019
Debt Instrument
Stated interest rate	2.70%
Outstanding Principal	$ 400	400
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 399.9	399.9
4.40% Senior unsecured notes due 2024
Debt Instrument
Stated interest rate	4.40%
Outstanding Principal	$ 550	550
Premium (Discount)	1.9	2.2
Long-Term Debt	$ 551.9	552.2
4.15% Senior unsecured notes due 2025
Debt Instrument
Stated interest rate	4.15%
Outstanding Principal	$ 750	750
Premium (Discount)	(0.9)	(1)
Long-Term Debt	$ 749.1	749
4.85% Senior unsecured notes due 2026
Debt Instrument
Stated interest rate	4.85%
Outstanding Principal	$ 500	500
Premium (Discount)	(0.5)	(0.6)
Long-Term Debt	$ 499.5	499.4
5.60% Senior unsecured notes due 2044
Debt Instrument
Stated interest rate	5.60%
Outstanding Principal	$ 350	350
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
5.05% Senior unsecured notes due 2045
Debt Instrument
Stated interest rate	5.05%
Outstanding Principal	$ 450	450
Premium (Discount)	(6.2)	(6.5)
Long-Term Debt	$ 443.8	443.5
5.45% Senior unsecured notes due 2047
Debt Instrument
Stated interest rate	5.45%		5.45%
Outstanding Principal	$ 500	500
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	9 Months Ended
	Sep. 30, 2018USD ($)extension	Dec. 31, 2017USD ($)
Debt Instrument
Outstanding borrowings under credit facility	$ 765,000,000	$ 0
Credit Facility
Debt Instrument
Maximum borrowing capacity	1,500,000,000
Additional amount available (not to exceed)	$ 500,000,000
Number of allowed extensions | extension	2
Extension period	1 year
Ratio of consolidated indebtedness to consolidated EBITDA	5
Outstanding letters of credit	$ 9,300,000
Outstanding borrowings under credit facility	765,000,000
Amount available for future borrowing	$ 725,700,000
Credit Facility | Federal Funds
Debt Instrument
Variable interest rate	0.50%
Credit Facility | Eurodollar
Debt Instrument
Variable interest rate	1.00%
Credit Facility | Maximum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5.5
Conditional acquisition purchase price	$ 50,000,000
Credit Facility | Maximum | LIBOR Rate
Debt Instrument
Variable interest rate	1.75%
Credit Facility | Maximum | Eurodollar
Debt Instrument
Variable interest rate	0.75%
Credit Facility | Minimum | LIBOR Rate
Debt Instrument
Variable interest rate	1.00%
Credit Facility | Minimum | Eurodollar
Debt Instrument
Variable interest rate	0.00%
Credit Facility | Letter of Credit
Debt Instrument
Maximum borrowing capacity	$ 500,000,000

Partners' Capital - Narrative a

Partners' Capital - Narrative and Distribution Activity (Details) - USD ($)	3 Months Ended								9 Months Ended
	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, 2018	Sep. 30, 2017	Aug. 30, 2017
Partners' capital
Proceeds from sale of common units									$ 46,100,000	$ 92,300,000
Proceeds from issuance of Series C Preferred Units									$ 0	393,700,000
Percentage of available cash to distribute									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)									$ 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)									$ 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)									$ 0.375
Series B Preferred Unitholders
Partners' capital
Preferred interest in net income attributable to ENLK	$ (24,300,000)				$ (22,800,000)				$ (69,000,000)	(63,600,000)
Distribution paid-in kind (in shares)	422,720	419,678	416,657	413,658	410,681	1,178,672	1,154,147	1,130,131
Proceeds from issuance of Series C Preferred Units	$ 16,400,000	$ 16,300,000	$ 16,200,000	$ 16,000,000	$ 15,900,000	$ 0	$ 0	$ 0
Distributions to preferred unitholders									48,500,000	0
Series C Preferred Unitholders
Partners' capital
Preferred interest in net income attributable to ENLK	$ (6,000,000)				$ (700,000)				(18,000,000)	(700,000)
Distributions to preferred unitholders									$ 12,000,000	0
Limited Partner
Partners' capital
Distribution declared per unit (in dollars per share)	$ 0.39								$ 0.39
Limited Partner | 2017 EDA
Partners' capital
Commission fees (less than)									$ 500,000
Limited Partner | Common Units
Partners' capital
Shelf registration for issuance of common units (up to)											$ 600,000,000
Issuance of common units (in shares)									2,600,000
Distribution declared per unit (in dollars per share)	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39
Limited Partner | Common Units | 2017 EDA
Partners' capital
Issuance of common units (in shares)									2,600,000
Proceeds from sale of common units									$ 46,100,000
Aggregate amount of equity security remaining under equity distribution agreement	$ 518,800,000								$ 518,800,000
Limited Partner | Series B Preferred Unitholders
Partners' capital
Distribution declared per unit (in dollars per share)									$ 0.28125
Annual rate on issue price payable in kind									0.25%
Shares issued, price per share (in dollars per share)	$ 15								$ 15
Preferred interest in net income attributable to ENLK	$ 24,300,000				$ 22,800,000				$ 69,000,000	$ 63,600,000
Limited Partner | Series C Preferred Unitholders
Partners' capital
Preferred interest in net income attributable to ENLK	$ 6,000,000				$ 700,000				$ 18,000,000
Dividend rate, percentage									6.00%

Partners' Capital - Computation

Partners' Capital - Computation of Basic and Diluted Earnings per Limited Partner Units (Details) - USD ($) $ / shares in Units, $ in Millions	Aug. 13, 2018	May 14, 2018	Nov. 13, 2017	Aug. 11, 2017	May 12, 2017	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, 2018	Sep. 30, 2017
Class of Stock [Line Items]
Limited partners’ interest in net income (loss)						$ 5.2				$ (8.6)				$ 85.7	$ (18.4)
Distributed earnings allocated to:
Total distributed earnings						138.5				136.8				413.5	408
Undistributed loss allocated to:
Total undistributed loss						(133.3)				(145.4)				(327.8)	(426.4)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)						$ 5.2				$ (8.6)				$ 85.7	$ (18.4)
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)						$ 0.01				$ (0.02)				$ 0.24	$ (0.05)
Diluted (in dollars per share)						$ 0.01				$ (0.02)				$ 0.24	$ (0.05)
Unvested restricted units
Class of Stock [Line Items]
Limited partners’ interest in net income (loss)						$ 0.1				$ 0				$ 0.6	$ (0.1)
Distributed earnings allocated to:
Total distributed earnings						1.2				1.1				3.1	3
Undistributed loss allocated to:
Total undistributed loss						(1.1)				(1.1)				(2.5)	(3.1)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)						$ 0.1				0				$ 0.6	(0.1)
Limited Partner
Basic and diluted net income (loss) per unit:
Distribution declared per unit (in dollars per share)						$ 0.39								$ 0.39
Distribution paid per unit (in dollars per share)	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39
Limited Partner | Common Units
Class of Stock [Line Items]
Limited partners’ interest in net income (loss)						$ 5.1				(8.6)				$ 85.1	(18.3)
Distributed earnings allocated to:
Total distributed earnings						137.3				135.7				410.4	405
Undistributed loss allocated to:
Total undistributed loss						(132.2)				(144.3)				(325.3)	(423.3)
Net income (loss) allocated to:
Total limited partners’ interest in net income (loss)						$ 5.1				$ (8.6)				$ 85.1	$ (18.3)
Basic and diluted net income (loss) per unit:
Distribution declared per unit (in dollars per share)						$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39

Partners' Capital - Unit Amount

Partners' Capital - Unit Amounts Used to Compute Earnings per Limited Partner Unit (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic weighted average units outstanding:
Weighted average limited partner basic common units outstanding (in shares)	351.9	347.9	350.7	346.1
Diluted weighted average units outstanding:
Total weighted average limited partner diluted common units outstanding (in shares)	353.5	347.9	352.2	346.1
Unvested restricted units
Diluted weighted average units outstanding:
Total weighted average limited partner diluted common units outstanding (in shares)	1.6	0	1.5	0
Limited Partner | Common Units
Diluted weighted average units outstanding:
Total weighted average limited partner diluted common units outstanding (in shares)	351.9	347.9	350.7	346.1

Partners' Capital - Net Income

Partners' Capital - Net Income Allocated to the General Partner (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Incentive
General partner interest in net income	$ 7.7	$ 10.6	$ 29.5	$ 27.3
General Partner Interest
Incentive
Income allocation for incentive distributions	15	14.8	44.6	44.1
Unit-based compensation attributable to ENLC’s restricted and performance units	(7.3)	(4.2)	(15.7)	(16.9)
General partner share of net income	0	0	0.6	0.1
General partner interest in net income	$ 7.7	$ 10.6	$ 29.5	$ 27.3

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Schedule of Equity Method Investments
Distributions	$ 5.3	$ 4	$ 16.7	$ 11.4
Equity in income (loss)	4.3	4.4	11.7	5
Contributions	0	1.5	0.1	11.8
Total investment in unconsolidated affiliates	$ 84.5		$ 84.5		$ 89.4
GCF
Schedule of Equity Method Investments
Ownership interest	38.75%		38.75%
Distributions	$ 5.3	3.5	$ 16.4	10.6
Equity in income (loss)	4.6	4.5	14	8.5
Total investment in unconsolidated affiliates	46		46		48.4
HEP
Schedule of Equity Method Investments
Equity in income (loss)	$ 0	0	$ 0	(3.4)
Cedar Cove JV
Schedule of Equity Method Investments
Ownership interest	30.00%		30.00%
Distributions	$ 0	0.5	$ 0.3	0.8
Equity in income (loss)	(0.3)	(0.1)	(2.3)	(0.1)
Contributions	0	$ 1.5	0.1	$ 11.8
Total investment in unconsolidated affiliates	$ 38.5		$ 38.5		$ 41

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Compensation allocation
Total unit-based compensation expense	$ 17	$ 10.1	$ 31.6	$ 38.7
Cost of unit-based compensation charged to operating expense
Compensation allocation
Total unit-based compensation expense	5.2	2.8	9.5	10.4
Cost of unit-based compensation charged to general and administrative expense
Compensation allocation
Total unit-based compensation expense	$ 11.8	$ 7.3	$ 22.1	$ 28.3

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	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Unvested restricted units
Number of Units
Non-vested, beginning of period (in shares)						1,980,224
Granted (in shares)						1,586,750
Vested (in shares)			(200,753)			(813,290)
Forfeited (in shares)						(157,057)
Non-vested, end of period (in shares)				2,596,627		2,596,627
Aggregate intrinsic value, end of period				$ 48.4		$ 48.4
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)						19.78
Forfeited (in dollars per share)						12.42
Non-vested, end of period (in dollars per share)				$ 14.44		$ 14.44
Vesting period						3 years
Fair value of units vested			$ 3	$ 2.8	$ 1.1	$ 16.1	$ 22.1
Units withheld for payroll taxes (in shares)						255,653
Aggregate intrinsic value of units vested				3.7	0.6	$ 12.8	16.3
Unrecognized compensation cost related to non-vested restricted incentive units				$ 22.2		$ 22.2
Unrecognized compensation costs, weighted average period for recognition						2 years
Unvested restricted units | ENLC
Number of Units
Non-vested, beginning of period (in shares)						1,889,310
Granted (in shares)						1,469,452
Vested (in shares)			(194,185)			(749,164)
Forfeited (in shares)						(146,045)
Non-vested, end of period (in shares)				2,463,553		2,463,553
Aggregate intrinsic value, end of period				$ 40.5		$ 40.5
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)						21.53
Forfeited (in dollars per share)						12.38
Non-vested, end of period (in dollars per share)				$ 14.64		$ 14.64
Vesting period						3 years
Fair value of units vested			$ 3	$ 2.6	1.1	$ 16.1	21.9
Units withheld for payroll taxes (in shares)						238,970
Aggregate intrinsic value of units vested				3.3	$ 0.6	$ 12.6	$ 15.2
Unrecognized compensation cost related to non-vested restricted incentive units				$ 21.5		$ 21.5
Unrecognized compensation costs, weighted average period for recognition						2 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)			0	(313,610)	0
Forfeited (in shares)						(76,351)
Non-vested, end of period (in shares)				451,669		451,669
Aggregate intrinsic value, end of period				$ 8.4		$ 8.4
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		$ 17.74
Vesting period						3 years
Fair value of units vested				$ 3.6		$ 7.7
Units withheld for payroll taxes (in shares)						112,101
Aggregate intrinsic value of units vested				3		$ 5
Unrecognized compensation cost related to non-vested restricted incentive units				6.2		$ 6.2
Unrecognized compensation costs, weighted average period for recognition						1 year 10 months
Additional unrecognized compensation expense related to non-vested restricted incentive units				$ 2.3		$ 2.3
Grant date fair value assumptions
Beginning TSR price (in dollars per share)			$ 15.44
Risk-free interest rate			2.38%
Volatility factor			43.85%
Distribution yield			10.50%
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)			0	(283,637)	0
Forfeited (in shares)						(70,918)
Non-vested, end of period (in shares)				418,149		418,149
Aggregate intrinsic value, end of period				$ 6.9		$ 6.9
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		$ 19.15
Vesting period						3 years
Fair value of units vested				$ 3.5		$ 7.7
Units withheld for payroll taxes (in shares)						100,109
Aggregate intrinsic value of units vested				2.8		$ 4.7
Unrecognized compensation cost related to non-vested restricted incentive units				6		$ 6
Unrecognized compensation costs, weighted average period for recognition						1 year 10 months
Additional unrecognized compensation expense related to non-vested restricted incentive units				$ 2.1		$ 2.1
Grant date fair value assumptions
Beginning TSR price (in dollars per share)			$ 16.55
Risk-free interest rate			2.38%
Volatility factor			51.36%
Distribution yield			6.70%
Performance Units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting	0.00%
Performance Units | Minimum | ENLC
Weighted Average Grant-Date Fair Value
Percent of units vesting						0.00%
Performance Units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting	100.00%					200.00%
Performance Units | Maximum | ENLC
Weighted Average Grant-Date Fair Value
Percent of units vesting	100.00%					200.00%

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	May 31, 2017
Derivative
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)
5.45% Senior unsecured notes due 2047
Derivative
Stated interest rate	5.45%		5.45%

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments
Loss on derivative activity	$ (5.4)	$ (5.5)	$ (20.1)	$ (1.1)
Commodity Swaps
Derivative Instruments
Change in fair value of derivatives	(0.8)	(3.3)	(14.8)	3.8
Realized loss on derivatives	(4.6)	(2.2)	(5.3)	(4.9)
Loss on derivative activity	$ (5.4)	$ (5.5)	$ (20.1)	$ (1.1)

Derivatives - Assets and Liabil

Derivatives - Assets and Liabilities (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivative assets—current	$ 12,500,000	$ 6,800,000
Fair value of derivative liabilities—current	(21,900,000)	(8,400,000)
Fair value of derivative liabilities—long-term	(7,000,000)	0
Net fair value of derivatives	(16,400,000)	(1,600,000)
Fair value of derivative assets - long-term	$ 0	$ 0

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)MMBTUgalMMBbls	Dec. 31, 2017USD ($)
Derivative
Fair Value	$ (16.4)	$ (1.6)
Possible reduction in maximum loss if counterparties fail to perform	0.1
Commodity
Derivative
Fair Value	(16.4)
Maximum loss if counterparties fail to perform	$ 12.5
Commodity | NGL | Short
Derivative
Notional amount (in gallons and mmbls) | gal	58.4
Fair Value	$ (12)
Commodity | NGL | Long
Derivative
Notional amount (in gallons and mmbls) | gal	18.9
Fair Value	$ 3.1
Commodity | Natural Gas | Short
Derivative
Notional amount (in mmbtu) | MMBTU	9
Fair Value	$ 0.4
Commodity | Natural Gas | Long
Derivative
Notional amount (in mmbtu) | MMBTU	10.9
Fair Value	$ (1.4)
Commodity | Crude and Condensate | Short
Derivative
Notional amount (in gallons and mmbls) | MMBbls	13.3
Fair Value	$ (13.2)
Commodity | Crude and Condensate | Long
Derivative
Notional amount (in gallons and mmbls) | MMBbls	1.3
Fair Value	$ 6.7

Fair Value Measurements - Measu

Fair Value Measurements - Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Measured at fair value
Fair Value	$ (16.4)	$ (1.6)
Level 2 | Commodity Swaps | Recurring
Measured at fair value
Fair Value	$ (16.4)	$ (1.6)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Fair Value
Debt issuance costs	$ 23,400,000	$ 25,900,000
Line of credit amount outstanding	765,000,000	0
Senior unsecured notes	$ 3,500,000,000	$ 3,500,000,000
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, including current maturities of long-term debt	$ 4,235,500,000	$ 3,467,800,000
Installment Payables	0	249,500,000
Obligations under capital lease	2,900,000	4,100,000
Secured Term Loan Receivable, Fair Value	49,900,000	0
Fair Value
Fair Value
Long-term debt, including current maturities of long-term debt	4,017,600,000	3,575,600,000
Installment Payables	0	249,600,000
Obligations under capital lease	2,500,000	3,400,000
Secured Term Loan Receivable, Fair Value	$ 49,900,000	$ 0

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting
Revenue from contracts with customers		$ 2,119.7		$ 5,660.8
Cost of sales	[1]	(1,696.6)	$ (1,053.2)	(4,403.7)	$ (2,987.9)
Operating expenses		(114.7)	(102.1)	(337.3)	(308.8)
Loss on derivative activity		(5.4)	(5.5)	(20.1)	(1.1)
Segment profit (loss)		303	242.6	899.7	686.7
Depreciation and amortization		(146.7)	(136.3)	(430.1)	(407.1)
Impairments		(24.6)	(1.8)	(24.6)	(8.8)
Goodwill		422.3	422.3	422.3	422.3	$ 422.3
Capital expenditures		253.3	169.7	652.7	636.3
Total identifiable assets		10,073.6		10,073.6		9,414
Corporate
Segment Reporting
Revenue from contracts with customers		(380.1)		(927.9)
Cost of sales		380.1	235.3	927.9	589.9
Operating expenses		0	0	0	0
Loss on derivative activity		(5.4)	(5.5)	(20.1)	(1.1)
Segment profit (loss)		(5.4)	(5.5)	(20.1)	(1.1)
Depreciation and amortization		(2.4)	(2.6)	(6.6)	(7.3)
Impairments		0	0	0	0
Goodwill		0	0	0	0
Capital expenditures		1.1	2.1	3.4	25.6
Total identifiable assets		183.9		183.9		144.5
Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		385.6		1,035.5
Cost of sales		(222)	(198.5)	(562.2)	(554.7)
Operating expenses		(44.7)	(41.1)	(134.7)	(127.9)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		118.9	107.6	338.6	314.6
Depreciation and amortization		(54)	(52.5)	(159.9)	(161.9)
Impairments		0	0	0	0
Goodwill		232	232	232	232
Capital expenditures		90	39.1	200	107.1
Total identifiable assets		3,161.9		3,161.9		3,094.8
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		1,010.5		2,592.6
Cost of sales		(923.6)	(662.7)	(2,333.3)	(1,803.1)
Operating expenses		(28.7)	(24.8)	(82.3)	(74.8)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		58.2	51	177	143.1
Depreciation and amortization		(32.7)	(29.3)	(92.4)	(86.8)
Impairments		(24.6)	0	(24.6)	0
Goodwill		0	0	0	0
Capital expenditures		13	7.5	36.4	55.8
Total identifiable assets		2,583.8		2,583.8		2,408.5
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		358		955.9
Cost of sales		(228.5)	(148.2)	(537.8)	(335.9)
Operating expenses		(22.5)	(17.1)	(64)	(45.9)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		107	79.1	354.1	201.3
Depreciation and amortization		(44.7)	(40.2)	(133.2)	(115.3)
Impairments		0	0	0	0
Goodwill		190.3	190.3	190.3	190.3
Capital expenditures		109.3	107.7	328.8	383.4
Total identifiable assets		3,074.1		3,074.1		2,836.7
Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		745.7		2,004.7
Cost of sales		(702.6)	(279.1)	(1,898.3)	(884.1)
Operating expenses		(18.8)	(19.1)	(56.3)	(60.2)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		24.3	10.4	50.1	28.8
Depreciation and amortization		(12.9)	(11.7)	(38)	(35.8)
Impairments		0	(1.8)	0	(8.8)
Goodwill		0	0	0	0
Capital expenditures		39.9	13.3	84.1	64.4
Total identifiable assets		1,069.9		1,069.9		$ 929.5
Product sales
Segment Reporting
Revenue from contracts with customers		1,832.2	1,056.7	4,766.5	2,973.9
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		85.9	80.8	225.7	240.5
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		969.2	642.3	2,453.3	1,735.5
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		55	42.5	146.5	84.7
Product sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		722.1	291.1	1,941	913.2
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers		240.5		714
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		69.1		208.9
Product sales, Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		129.5		377.2
Product sales, Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		41.9		127.9
Product sales, Natural gas sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers		869.3		2,111.9
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, NGL sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		16.8		16.8
Product sales, NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		839.6		2,075.9
Product sales, NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		12.8		18.3
Product sales, NGL sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.9
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers		722.4		1,940.6
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Crude oil and condensate sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.2
Product sales, Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.3		0.3
Product sales, Crude oil and condensate sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		722		1,940.1
Product sales—related parties
Segment Reporting
Revenue from contracts with customers		10.2	35.3	41	107.3
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(380.1)	(199.9)	(927.9)	(493.1)
Product sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		167.2	130.6	420.5	352.6
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		11	10	45.7	25.6
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		210.6	94.6	499.4	221.4
Product sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		1.5	0	3.3	0.8
Product sales, Natural gas sales, related party
Segment Reporting
Revenue from contracts with customers		0.1		2.5
Product sales, Natural gas sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Natural gas sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		2.5
Product sales, Natural gas sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers		10		37.4
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(347.2)		(822.1)
Product sales, NGL sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		153.8		381.1
Product sales, NGL sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.9		45.4
Product sales, NGL sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		192.5		433
Product sales, NGL sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers		0.1		1.1
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(32.9)		(105.8)
Product sales, Crude oil and condensate sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		13.4		39.4
Product sales, Crude oil and condensate sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.3
Product sales, Crude oil and condensate sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		18		63.9
Product sales, Crude oil and condensate sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		1.5		3.3
Midstream services
Segment Reporting
Revenue from contracts with customers		241.5	136.4	476.1	395.7
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		113.5	29.1	157.5	85.1
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		30.3	50.3	93.6	159.7
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		81.9	44.3	179.5	105.2
Midstream services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		15.8	12.7	45.5	45.7
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers		140.2		244.1
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Gathering and transportation | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		71.7		98.4
Midstream services, Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		17.5		51.8
Midstream services, Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		50.2		91.4
Midstream services, Gathering and transportation | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.8		2.5
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers		71.7		143.1
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Processing | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		39.4		52.7
Midstream services, Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.8		2.5
Midstream services, Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		31.5		87.9
Midstream services, Processing | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers		11.9		38.8
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		11.9		38.8
Midstream services, NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, NGL services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers		15.1		43
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.2		0.2
Midstream services, Crude services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		14.9		42.8
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers		2.6		7.1
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Other services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		2.4		6.4
Midstream services, Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Other services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.2
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers		35.8	175	377.2	507.6
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		0	(35.4)	0	(96.8)
Midstream services—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		19	106.7	231.8	319
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0	35.9	0	100.2
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.5	63	130.5	171.8
Midstream services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		6.3	$ 4.8	14.9	$ 13.4
Midstream services, Gathering and transportation, related party
Segment Reporting
Revenue from contracts with customers		15.9		203.3
Midstream services, Gathering and transportation, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Gathering and transportation, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		8.7		122.7
Midstream services, Gathering and transportation, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Gathering and transportation, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		7.2		80.6
Midstream services, Gathering and transportation, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Processing, related party
Segment Reporting
Revenue from contracts with customers		13.4		157
Midstream services, Processing, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Processing, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.2		108.6
Midstream services, Processing, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Processing, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		3.2		48.4
Midstream services, Processing, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers		6.4		16.4
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Crude services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		1.5
Midstream services, Crude services, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		6.3		14.9
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Other services, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Other services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0		0
Midstream services, Other services, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		$ 0		$ 0
[1]	Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting [Abstract]
Segment profit	$ 303	$ 242.6	$ 899.7	$ 686.7
General and administrative expenses	(39.2)	(30)	(94.5)	(94.6)
Loss on disposition of assets	0	(1.1)	(1.3)	(0.8)
Depreciation and amortization	(146.7)	(136.3)	(430.1)	(407.1)
Impairments	(24.6)	(1.8)	(24.6)	(8.8)
Gain on litigation settlement	0	0	0	26
Operating income	$ 92.5	$ 73.4	$ 349.2	$ 201.4

Other Information (Details)

Other Information (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Other Current Assets:
Natural gas and NGLs inventory	$ 119,400,000	$ 30,100,000
Secured term loan receivable from contract restructuring, net of discount of $1.1	18,400,000	0
Secured term loan receivable, discount	1,600,000	0
Prepaid expenses and other	15,600,000	9,600,000
Natural gas and NGLs inventory, prepaid expenses, and other	153,400,000	39,700,000
Other Current Liabilities:
Accrued interest	64,500,000	35,400,000
Accrued wages and benefits, including taxes	24,800,000	30,400,000
Accrued ad valorem taxes	33,400,000	27,800,000
Capital expenditure accruals	57,900,000	48,800,000
Onerous performance obligations	13,500,000	15,200,000
Other	65,700,000	64,800,000
Other current liabilities	$ 259,800,000	$ 222,400,000

Subsequent Event (Details)

Subsequent Event (Details)	Oct. 21, 2018
Subsequent Event
Subsequent Event [Line Items]
Partners Capital, Common Units Conversion Ratio	1.15