EnLink Midstream (ENLC) 10-Q 1 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 26, 2017
Entity Information [Abstract]
Document Type	10-Q
Document Fiscal Period Focus	Q3
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Amendment Flag	false
Entity Registrant Name	Enlink Midstream, LLC
Entity Central Index Key	1,592,000
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		180,589,927

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 141.9	$ 11.7
Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.1, respectively	42.5	63.9
Accrued revenue and other	432.4	369.6
Related party	121.5	100.2
Fair value of derivative assets	4.6	1.3
Natural gas and NGLs inventory, prepaid expenses and other	73.4	33.5
Investment in unconsolidated affiliates—current	0	193.1
Total current assets	816.3	773.3
Property and equipment, net of accumulated depreciation of $2,428.5 and $2,124.1, respectively	6,568.8	6,256.7
Fair value of derivative assets	0.1	0
Intangible assets, net of accumulated amortization of $267.8 and $171.6, respectively	1,528	1,624.2
Goodwill	1,542.2	1,542.2
Investment in unconsolidated affiliates—non-current	86.1	77.3
Other assets, net	6.8	2.2
Total assets	10,548.3	10,275.9
Current liabilities:
Accounts payable and drafts payable	65.2	69.2
Accounts payable to related party	36.8	10.4
Accrued gas, NGLs, condensate and crude oil purchases	376.6	333.3
Fair value of derivative liabilities	7.2	7.6
Installment payable, net of discount of $7.0 and $0.5, respectively	243	249.5
Other current liabilities	235.2	217.5
Total current liabilities	964	887.5
Long-term debt	3,540.5	3,295.3
Asset retirement obligations	14	13.5
Installment payable, net of discount of $26.3 at December 31, 2016	0	223.7
Other long-term liabilities	38.7	42.5
Deferred tax liability	550.2	542.6
Redeemable non-controlling interest	4.6	5.2
Members’ equity:
Members’ equity (180,586,977 and 180,049,316 units issued and outstanding, respectively)	1,763.5	1,880.9
Accumulated other comprehensive loss	(2)	0
Non-controlling interest	3,674.8	3,384.7
Total members’ equity	5,436.3	5,265.6
Commitments and contingencies (Note 15)
Total liabilities and members’ equity	$ 10,548.3	$ 10,275.9

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
ASSETS
Allowance for bad debt	$ 0.1	$ 0.1
Property and equipment, accumulated depreciation	2,428.5	2,124.1
Intangible assets, accumulated amortization	267.8	171.6
Liabilities:
Current installment payable discount	7	0.5
Noncurrent installment payable discount	$ 0	$ 26.3
Members’ equity:
Common units issued (in shares)	180,586,977	180,049,316
Common units outstanding (in shares)	180,586,977	180,049,316

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Product sales		$ 1,056.7	$ 771	$ 2,973.9	$ 2,097.8
Product sales—related parties		35.3	43.1	107.3	99.3
Midstream services		136.4	125.7	395.7	348.5
Midstream services—related parties		175	165.3	507.6	488.5
Loss on derivative activity		(5.5)	(0.5)	(1.1)	(6.6)
Total revenues		1,397.9	1,104.6	3,983.4	3,027.5
Operating costs and expenses:
Cost of sales	[1]	1,053.2	788.2	2,987.9	2,106.8
Operating expenses		102.1	98	308.8	296.3
General and administrative		31.3	29.3	98.5	94.7
(Gain) loss on disposition of assets		1.1	(3)	0.8	(2.9)
Depreciation and amortization		136.3	126.2	407.1	373
Impairments		1.8	0	8.8	873.3
Gain on litigation settlement		0	0	(26)	0
Total operating costs and expenses		1,325.8	1,038.7	3,785.9	3,741.2
Operating income (loss)		72.1	65.9	197.5	(713.7)
Other income (expense):
Interest expense, net of interest income		(49.6)	(48.4)	(142.2)	(138.9)
Gain on extinguishment of debt		0	0	9	0
Income (loss) from unconsolidated affiliates		4.4	1.1	5	(0.5)
Other income		0.3	0.1	0.5	0.1
Total other expense		(44.9)	(47.2)	(127.7)	(139.3)
Income (loss) before non-controlling interest and income taxes		27.2	18.7	69.8	(853)
Income tax provision		(3.1)	(7.6)	(9.3)	(6)
Net income (loss)		24.1	11.1	60.5	(859)
Net income (loss) attributable to non-controlling interest		17.9	10.4	50.3	(402.9)
Net income (loss) attributable to EnLink Midstream, LLC		$ 6.2	$ 0.7	$ 10.2	$ (456.1)
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit (in dollars per share)		$ 0.03	$ 0	$ 0.06	$ (2.54)
Diluted common unit (in dollars per share)		$ 0.03	$ 0	$ 0.06	$ (2.54)
[1]	Includes related party cost of sales of $47.3 million and $33.7 million for the three months ended September 30, 2017 and 2016, respectively, and $126.9 million and $126.0 million for the nine months ended September 30, 2017 and 2016, respectively.

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Related party cost of sales	$ 47.3	$ 33.7	$ 126.9	$ 126

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) Statement - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 24.1	$ 11.1	$ 60.5	$ (859)
Loss on designated cash flow hedge, net of tax benefit of $0.2 million	0	0	(2)	0
Comprehensive income (loss)	24.1	11.1	58.5	(859)
Comprehensive income (loss) attributable to non-controlling interest	17.9	10.4	48.7	(402.9)
Comprehensive income (loss) attributable to EnLink Midstream, LLC	$ 6.2	$ 0.7	$ 9.8	$ (456.1)

Consolidated Statements of Com7

Consolidated Statements of Comprehensive Income (Loss) Parenthetical $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Statement of Comprehensive Income [Abstract]
Loss on designated cash flow hedge tax benefit	$ 0.2

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - 9 months ended Sep. 30, 2017 - USD ($) $ in Millions	Total	Common Units	Accumulated Other Comprehensive Loss	Non-Controlling Interest	Redeemable Non-Controlling Interest (Temporary Equity)
Member equity, beginning balance at Dec. 31, 2016	$ 5,265.6	$ 1,880.9	$ 0	$ 3,384.7
Units outstanding, beginning balance (in shares) at Dec. 31, 2016	180,049,316	180,000,000
Increase (Decrease) in Members' Equity
Issuance of common units by ENLK	$ 92.3			92.3
Issuance of preferred units by ENLK	393.7			393.7
Conversion of restricted units for common units, net of units withheld for taxes	(5)	$ (5)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)		600,000
Non-controlling interest’s impact of conversion of restricted units	(5.2)			(5.2)
Unit-based compensation	34.5	$ 17.2		17.3
Change in equity due to issuance of units by ENLK	0.2	(0.3)		0.5
Non-controlling interest distributions	(306.3)			(306.3)	$ (0.6)
Non-controlling interest contribution	46.2			46.2
Distributions to members	(139.5)	(139.5)
Contribution from Devon to ENLK	1.3			1.3
Loss on designated cash flow hedge	(2)		(2)
Net income	60.5	10.2		50.3
Member equity, end balance at Sep. 30, 2017	$ 5,436.3	$ 1,763.5	$ (2)	3,674.8
Units outstanding, end balance (in shares) at Sep. 30, 2017	180,586,977	180,600,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2016					5.2
Increase (Decrease) in Temporary Equity
Distributions to redeemable non-controlling interest	$ (306.3)			$ (306.3)	(0.6)
Redeemable noncontrolling interest, ending balance at Sep. 30, 2017					$ 4.6

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ 60.5	$ (859)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	8.8	873.3
Depreciation and amortization	407.1	373
(Gain) loss on disposition of assets	0.8	(2.9)
Non-cash unit-based compensation	38.9	22.5
Loss on derivatives recognized in net income (loss)	1.1	6.6
Gain on extinguishment of debt	(9)	0
Cash settlements on derivatives	(5.9)	9.5
Amortization of debt issue costs	3	2.9
Amortization of net discount on notes and installment payable	18.8	36.9
Redeemable non-controlling interest expense	0	0.3
(Income) loss from unconsolidated affiliates	(5)	0.5
Other	12.6	5.5
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other	(56.7)	(17.9)
Natural gas and NGLs inventory, prepaid expenses and other	(48.4)	11.9
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	101.8	49.4
Net cash provided by operating activities	528.4	512.5
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(662.5)	(423.7)
Acquisition of business, net of cash acquired	0	(791.5)
Proceeds from insurance settlement	0.2	0.3
Proceeds from sale of unconsolidated affiliate investment	189.7	0
Proceeds from sale of property	1.8	4.7
Investment in unconsolidated affiliates	(11.8)	(45)
Distribution from unconsolidated affiliates in excess of earnings	7.3	51.6
Net cash used in investing activities	(475.3)	(1,203.6)
Cash flows from financing activities:
Proceeds from borrowings	2,213.4	1,667.7
Payments on borrowings	(1,955.6)	(1,484.5)
Payment of installment payable for EnLink Oklahoma T.O. acquisition	(250)	0
Payments on capital lease obligations	(2.1)	(3.2)
Debt financing costs	(5.5)	(4.7)
Mandatorily redeemable non-controlling interest	0	(4)
Conversion of restricted units, net of units withheld for taxes	(5)	(1.2)
Conversion of ENLK restricted units, net of units withheld for taxes	(5.2)	(1.2)
Proceeds from issuance of ENLK common units	92.3	110.6
Distributions to non-controlling interests	(306.9)	(284.3)
Distribution to members	(139.5)	(139)
Contribution from Devon	1.3	1.4
Contributions by non-controlling interests	46.2	151.5
Net cash provided by financing activities	77.1	733.2
Net increase in cash and cash equivalents	130.2	42.1
Cash and cash equivalents, beginning of period	11.7	18
Cash and cash equivalents, end of period	141.9	60.1
Cash paid for interest	94.7	71.2
Cash paid (refund) for income taxes	4.1	(5.6)
Series B Preferred Unitholders
Cash flows from financing activities:
Proceeds from issuance of ENLK Series Preferred Units	0	724.1
Series C Preferred Unitholders
Cash flows from financing activities:
Proceeds from issuance of ENLK Series Preferred Units	$ 393.7	$ 0

General

General	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	(1) General In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” “us,” and “its,” are sometimes used as abbreviated references to EnLink Midstream, LLC and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership” and “ENLK” refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries. (a) Organization of Business EnLink Midstream, LLC is a publicly traded Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” Our assets consist of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. ENLK is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O. is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As of September 30, 2017 , our interests in ENLK and EnLink Oklahoma T.O. consist of the following: • 88,528,451 common units representing an aggregate 21.8% limited partner interest in ENLK; • 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of ENLK (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK; and • 16% limited partner interest in EnLink Oklahoma T.O. (b) Nature of Business We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing to producers of natural gas, NGLs , crude oil and condensate. We connect the wells of producers in our market areas to our gathering systems, which consist of networks of pipelines that collect natural gas from points 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, which is transported to the plants by our own gathering systems or by major interstate and intrastate 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, other markets 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 through our transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants. 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 transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. We also provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We have crude oil and condensate terminal facilities that provide market access for crude oil and condensate producers.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
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 generally accepted accounting principles in the United States of America (“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) Adopted Accounting Standards In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which simplifies several aspects related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adopted the guidance that requires excess tax benefits and deficiencies be recognized on the income statement. The cash flow statement guidance requires the presentation of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of the new guidance did not materially affect the consolidated statements of operations for the three and nine months ended September 30, 2017 . In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350) — Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, Intangibles — Goodwill and Other (“ASC 350”). As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04. (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”). 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. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheets 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 addition, there are industry-specific concerns with the implementation of ASU 2016-02, including the application of ASU 2016-02 to contracts involving easements/right-of-ways, which will require further evaluation before we are able to fully assess the impact on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require 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 will also require 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. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018. We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer from our customer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. 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 will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time 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 will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. This reclassification of revenues and costs will have no effect on operating income. Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, ASC 606 will not significantly affect the timing of income and expense on the statement of operations, and we will continue to recognize revenue at the time commodities are delivered or services are performed. Based on the disclosure requirements of ASC 606, upon adoption, we expect to provide expanded disclosures relating to our revenue recognition policies and how these relate to our revenue-generating contractual performance obligations. In addition, we expect to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. (d) Property & Equipment Impairment Review. We evaluate our property and equipment 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 nine months ended September 30, 2017 , we recognized impairments of $8.8 million , which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. (e) Comprehensive Income (Loss) Comprehensive income (loss) is composed of net income (loss) and other comprehensive income (loss), which consists of the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”). For the three and nine months ended September 30, 2017 , we reclassified an immaterial amount of losses from accumulated other comprehensive income (loss) to earnings. For additional information, see “ Note 13—Derivatives .”

Acquisition

Acquisition	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Acquisition	(3) Acquisition On January 7, 2016, ENLC and ENLK acquired a 16% and 84% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion . The first installment of $1.02 billion for the acquisition was paid at closing. The second installment of $250.0 million was paid on January 6, 2017, and the final installment of $250.0 million is due no later than January 7, 2018. ENLK’s installment payables are valued net of discount within the total purchase price. The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by ENLK, which was primarily derived from the issuance of Series B Cumulative Convertible Preferred Units (“Series B Preferred Units”), (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and (c) approximately $22.2 million in cash paid by ENLC. The transaction was accounted for using the acquisition method. The following table presents the consideration ENLC and ENLK paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration: Cash $ 805.8 Issuance of ENLC common units 214.9 ENLK’s total installment payable, net of discount of $79.1 million assuming payments made on January 7, 2017 and 2018 420.9 Total consideration $ 1,441.6 Purchase Price Allocation: Assets acquired: Current assets (including $12.8 million in cash) $ 23.0 Property, plant and equipment 406.1 Intangibles 1,051.3 Liabilities assumed: Current liabilities (38.8 ) Total identifiable net assets $ 1,441.6 The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years . We incurred a total of $4.8 million of direct transaction costs, of which $4.4 million was recognized as expense for the nine months ended September 30, 2016 . These costs are included in general and administrative expenses in the accompanying consolidated statements of operations. For the three and nine months ended September 30, 2016 , we recognized $77.3 million and $149.5 million of revenues, respectively, and $4.4 million and $27.9 million of net loss , respectively, related to the assets acquired.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	9 Months Ended
	Sep. 30, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	(4) Goodwill and Intangible Assets Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. During February 2016, we determined that weakness in the overall energy sector, driven by low commodity prices, together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for our Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss on the consolidated statement of operations for the nine months ended September 30, 2016 . We concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit is recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis. During the first quarter of 2017, we elected to early adopt ASU 2017-04, which simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350. Although no goodwill impairment tests were required during the nine months ended September 30, 2017, we will perform future goodwill impairment tests according to ASU 2017-04. For additional information, see “ Note 2—Significant Accounting Policies .” 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 ten to twenty 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, 2017 Customer relationships, beginning of period $ 1,795.8 $ (171.6 ) $ 1,624.2 Amortization expense — (96.2 ) (96.2 ) Customer relationships, end of period $ 1,795.8 $ (267.8 ) $ 1,528.0 The weighted average amortization period is 15.0 years . Amortization expense was approximately $31.2 million and $29.9 million for the three months ended September 30, 2017 and 2016 , respectively, and $96.2 million and $87.4 million for the nine months ended September 30, 2017 and 2016 , respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2017 (remaining) $ 30.8 2018 123.4 2019 123.4 2020 123.4 2021 123.4 Thereafter 1,003.6 Total $ 1,528.0

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions	(5) Related Party Transactions We engage in various transactions with Devon Energy Corporation (“Devon”) and other related parties. For the three and nine months ended September 30, 2017 , Devon accounted for 15.0% and 15.4% of our revenues, respectively, and for the three and nine months ended September 30, 2016 , Devon accounted for 18.9% and 19.4% of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $121.5 million at September 30, 2017 and $100.2 million at December 31, 2016 . Additionally, we had an accounts payable balance related to transactions with Devon of $36.8 million at September 30, 2017 and $10.4 million at December 31, 2016 . Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with unrelated third parties. 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, 2017
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of September 30, 2017 and December 31, 2016 , long-term debt consisted of the following (in millions): September 30, 2017 December 31, 2016 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt ENLK credit facility due 2020 (1) $ — $ — $ — $ 120.0 $ — $ 120.0 ENLC credit facility due 2019 (2) 74.0 — 74.0 27.8 — 27.8 2.70% Senior unsecured notes due 2019 400.0 (0.2 ) 399.8 400.0 (0.3 ) 399.7 7.125% Senior unsecured notes due 2022 — — — 162.5 16.0 178.5 4.40% Senior unsecured notes due 2024 550.0 2.3 552.3 550.0 2.5 552.5 4.15% Senior unsecured notes due 2025 750.0 (1.0 ) 749.0 750.0 (1.1 ) 748.9 4.85% Senior unsecured notes due 2026 500.0 (0.6 ) 499.4 500.0 (0.7 ) 499.3 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 (6.5 ) 443.5 450.0 (6.6 ) 443.4 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 — — — Debt classified as long-term $ 3,574.0 $ (6.3 ) $ 3,567.7 $ 3,310.3 $ 9.6 $ 3,319.9 Debt issuance cost (3) (27.2 ) (24.6 ) Long-term debt, net of unamortized issuance cost $ 3,540.5 $ 3,295.3 (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% at December 31, 2016 . (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.2% and 3.4% at September 30, 2017 and December 31, 2016 , respectively. (3) Net of amortization of $11.9 million and $9.0 million at September 30, 2017 and December 31, 2016 , respectively. ENLC Credit Facility We have a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility (the “ENLC Credit Facility”). Our obligations under the ENLC Credit Facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 ENLK common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility. The ENLC Credit Facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the ENLC Credit Facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 unless an investment grade event (as defined in the ENLC Credit Facility) occurs. Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50% ) or the Base Rate (the highest of the Federal Funds Rate plus 0.5% , the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.75% to 1.50% ). The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the ENLC Credit Facility, amounts outstanding under the ENLC Credit Facility, if any, may become due and payable immediately and the liens securing the ENLC Credit Facility could be foreclosed upon. At September 30, 2017 , ENLC was in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility for at least the next twelve months. As of September 30, 2017 , there were no outstanding letters of credit and $74.0 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $176.0 million available for future borrowing based on the borrowing capacity of $250.0 million . ENLK Credit Facility ENLK has a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 (the “ENLK Credit Facility”), which includes a $500.0 million letter of credit subfacility. Under the ENLK Credit Facility, ENLK is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the ENLK 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 the ENLK Credit Facility by one year on each occasion. The ENLK 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 the ENLK Credit Facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If ENLK consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLK 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 the ENLK Credit Facility bear interest at ENLK’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75% ) or the Base Rate (the highest of the Federal Funds Rate plus 0.50% , the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from zero percent to 0.75% ). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately. At September 30, 2017 , ENLK was in compliance and expects to be in compliance with the covenants in the ENLK Credit Facility for at least the next twelve months. As of September 30, 2017 , there were $9.2 million in outstanding letters of credit and no outstanding borrowings under the ENLK Credit Facility, leaving approximately $1.5 billion available for future borrowing. All other material terms and conditions of the ENLK Credit Facility 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, 2016 . Senior Unsecured Notes due 2047 On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of ENLK’s 5.450% senior unsecured notes due June 1, 2047 (the “2047 Notes”) at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes. Redemption of Senior Unsecured Notes due 2022 On June 1, 2017, ENLK redeemed $162.5 million in aggregate principal amount of ENLK’s 7.125% senior unsecured notes (the “2022 Notes”) at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million , which resulted in a gain on extinguishment of debt of $9.0 million for the nine months ended September 30, 2017 .

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	(7) Income Taxes Income taxes included on the consolidated financial statements were as follows for the periods presented (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 ENLC income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0 Total income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0 The following schedule reconciles total income tax expense (benefit) and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Tax expense (benefit) at statutory federal rate (35%) $ 3.3 $ 2.0 $ 6.8 $ (158.0 ) State income taxes expense (benefit), net of federal tax benefit 0.2 3.1 0.5 (11.8 ) Income tax expense from partnership 0.5 2.6 0.7 1.3 Unit-based compensation (1) — — 2.3 — Non-deductible expense related to asset impairment — (0.1 ) — 173.8 Other (0.9 ) — (1.0 ) 0.7 Total income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0 (1) Related to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.

Certain Provisions of the Partn

Certain Provisions of the Partnership Agreement	9 Months Ended
	Sep. 30, 2017
Partners' Capital [Abstract]
Certain Provisions of the Partnership Agreement	(8) Certain Provisions of the Partnership Agreement (a) Issuance of ENLK Common Units In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program. In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (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 ENLK common units from time to time through an “at the market” equity offering program. ENLK 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. ENLK has 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, 2017 , ENLK sold an aggregate of approximately 5.3 million common units under the 2014 EDA and 2017 EDA, generating proceeds of approximately $92.3 million (net of approximately $0.9 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. As of September 30, 2017 , approximately $580.1 million remains available to be issued under the 2017 EDA. (b) ENLK Series B Preferred Units In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units representing ENLK limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund ENLK’s portion of the purchase price payable in connection with the acquisition of ENLK’s EnLink Oklahoma T.O. assets. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Series B Preferred Units are convertible into ENLK common units on a one -for-one basis, subject to certain adjustments (a) in full, at ENLK’s option, if the volume weighted average price of a common unit over the 30 -trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of ENLK’s general partner or the managing member of ENLC, all of the Series B Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Series B Preferred Units would then convert and (ii) the number of Series B Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP. For the quarter ended March 31, 2016 through the quarter ended June 30, 2017, Enfield received a quarterly distribution equal to an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Series B Preferred Units. For the quarter ended September 30, 2017 and each subsequent quarter, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to an annual rate of 7.5% on the Issue Price payable in cash (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. A summary of the distribution activity relating to the Series B Preferred Units for the nine months ended September 30, 2017 and 2016 is provided below: Declaration period Distribution paid-in kind (1) Cash Distribution (in millions) Date paid/payable 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 2016 First Quarter of 2016 992,445 $ — May 12, 2016 Second Quarter of 2016 1,083,589 $ — August 11, 2016 Third Quarter of 2016 1,106,616 $ — November 10, 2016 (1) Represents distributions paid or payable on the Series B Preferred Units through issuance of additional Series B Preferred Units. (c) Issuance of ENLK Series C Preferred Units In September 2017, ENLK issued 400,000 Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series C Preferred Units”) representing ENLK limited partner interests at a price to the public of $1,000 per unit. ENLK used the net proceeds of $393.7 million for capital expenditures, general partnership purposes and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLK indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units will rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event. Income is allocated to the Series C Preferred Units in an amount equal to the earned distributions for the respective reporting period. At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at ENLK’s option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared. Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 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 ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11% . (d) ENLK Common Unit Distributions Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s unsecured senior notes, ENLK must make distributions of 100% of available cash, as defined in its partnership agreement, within 45 days following the end of each quarter. Distributions are made to the 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 ENLK Series B Preferred Units until such units convert into common units or (ii) the Series C Preferred Units. The General Partner owns the general partner interest in ENLK and all of its incentive distribution rights. The General Partner is entitled to receive incentive distributions if the amount ENLK distributes with respect to any quarter exceeds levels specified in its partnership agreement. Under the quarterly incentive distribution provisions, the General Partner is entitled to 13.0% of amounts ENLK distributes in excess of $0.25 per unit, 23.0% of the amounts ENLK distributes in excess of $0.3125 per unit and 48.0% of amounts ENLK distributes in excess of $0.375 per unit. A summary of ENLK’s distribution activity relating to the common units for the nine months ended September 30, 2017 and 2016 is provided below: Declaration period Distribution/unit Date paid/payable 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 2016 Fourth Quarter of 2015 $ 0.39 February 11, 2016 First Quarter of 2016 $ 0.39 May 12, 2016 Second Quarter of 2016 $ 0.39 August 11, 2016 Third Quarter of 2016 $ 0.39 November 11, 2016 (e) Allocation of ENLK Income Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in (d) above. The 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 ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Income allocation for incentive distributions $ 14.8 $ 14.4 $ 44.1 $ 42.4 Unit-based compensation attributable to ENLC’s restricted units (4.2 ) (3.6 ) (16.9 ) (11.2 ) General Partner share of net income (loss) — — 0.1 (2.4 ) General Partner interest in net income $ 10.6 $ 10.8 $ 27.3 $ 28.8

Members' Equity

Members' Equity	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Members' Equity	(9) Members' Equity (a) Earnings Per Unit and Dilution Computations As required under ASC 260, Earnings Per Share , unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions, except per unit amounts): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 EnLink Midstream, LLC interest in net income (loss) $ 6.2 $ 0.7 $ 10.2 $ (456.1 ) Distributed earnings allocated to: Common units (1) (2) $ 46.0 $ 45.9 $ 138.0 $ 137.4 Unvested restricted units (1) (2) 0.7 0.6 1.9 1.6 Total distributed earnings $ 46.7 $ 46.5 $ 139.9 $ 139.0 Undistributed loss allocated to: Common units $ (39.9 ) $ (45.1 ) $ (128.0 ) $ (588.3 ) Unvested restricted units (0.6 ) (0.7 ) (1.7 ) (6.8 ) Total undistributed loss $ (40.5 ) $ (45.8 ) $ (129.7 ) $ (595.1 ) Net income (loss) allocated to: Common units $ 6.1 $ 0.8 $ 10.0 $ (450.9 ) Unvested restricted units 0.1 (0.1 ) 0.2 (5.2 ) Total net income (loss) $ 6.2 $ 0.7 $ 10.2 $ (456.1 ) Basic and diluted net income (loss) per unit: Basic $ 0.03 $ — $ 0.06 $ (2.54 ) Diluted $ 0.03 $ — $ 0.06 $ (2.54 ) (1) For the three months ended September 30, 2017 and 2016 , distributed earnings included a declared distribution of $0.255 per unit payable on November 14, 2017 and a distribution of $0.255 per unit paid on November 14, 2016 , respectively. (2) For the nine months ended September 30, 2017 , distributed earnings included distributions of $0.255 per unit paid on May 15, 2017 and August 14, 2017 and a declared distribution of $0.255 per unit payable on November 14, 2017 . For the nine months ended September 30, 2016 , distributed earnings included distributions of $0.255 per unit paid on May 13, 2016 , $0.255 per unit paid on August 12, 2016 , and $0.255 per unit paid on November 14, 2016 . 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, 2017 2016 2017 2016 Basic and diluted earnings per unit: Weighted average common units outstanding 180.6 180.0 180.4 179.6 Diluted weighted average units outstanding: Weighted average basic common units outstanding 180.6 180.0 180.4 179.6 Dilutive effect of non-vested restricted incentive units (1) 1.2 1.1 1.3 — Total weighted average diluted common units outstanding 181.8 181.1 181.7 179.6 (1) For the nine months ended September 30, 2016 , all common unit equivalents were antidilutive since a net loss existed for that period. 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. (b) Distributions A summary of our distribution activity relating to the ENLC common units for the nine months ended September 30, 2017 and 2016 , respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2017 Fourth Quarter of 2016 $ 0.255 February 14, 2017 First Quarter of 2017 $ 0.255 May 15, 2017 Second Quarter 2017 $ 0.255 August 14, 2017 Third Quarter 2017 $ 0.255 November 14, 2017 2016 Fourth Quarter of 2015 $ 0.255 February 12, 2016 First Quarter of 2016 $ 0.255 May 13, 2016 Second Quarter 2016 $ 0.255 August 12, 2016 Third Quarter 2016 $ 0.255 November 14, 2016

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(10) Asset Retirement Obligations The schedule below summarizes the changes in our asset retirement obligations (in millions): Nine Months Ended September 30, 2017 Balance, beginning of period $ 13.5 Accretion expense 0.5 Balance, end of period $ 14.0 Asset retirement obligations of $14.0 million and $13.5 million were included in “Asset retirement obligations” as non-current liabilities on the consolidated balance sheets as of September 30, 2017 and December 31, 2016 , respectively.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(11) Investment in Unconsolidated Affiliates Our unconsolidated investments consisted of: • a contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) at September 30, 2017 and December 31, 2016 ; • an approximate 30% ownership in Cedar Cove Midstream LLC (the “Cedar Cove JV”) at September 30, 2017 and December 31, 2016 . On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, the heart of the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties play; and • an approximate 31% common unit ownership interest in Howard Energy Partners (“HEP”) at December 31, 2016 , which was sold in March 2017 for aggregate net proceeds of $189.7 million . The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Gulf Coast Fractionators Contributions $ — $ — $ — $ — Distributions $ 3.5 $ 0.9 $ 10.6 $ 4.4 Equity in income $ 4.5 $ 2.2 $ 8.5 $ 1.1 Howard Energy Partners Contributions (1) $ — $ 3.2 $ — $ 45.0 Distributions (2) $ — $ 36.5 $ — $ 47.9 Equity in loss (3) $ — $ (1.1 ) $ (3.4 ) $ (1.6 ) Cedar Cove JV Contributions $ 1.5 $ — $ 11.8 $ — Distributions $ 0.5 $ — $ 0.8 $ — Equity in loss $ (0.1 ) $ — $ (0.1 ) $ — Total Contributions (1) $ 1.5 $ 3.2 $ 11.8 $ 45.0 Distributions (2) $ 4.0 $ 37.4 $ 11.4 $ 52.3 Equity in income (loss) (3) $ 4.4 $ 1.1 $ 5.0 $ (0.5 ) (1) Contributions for the three and nine months ended September 30, 2016 included $3.2 million and $32.7 million , respectively, of contributions to HEP for preferred units issued by HEP, which were redeemed during the third quarter of 2016. (2) Distributions for the three and nine months ended September 30, 2016 included a redemption of $32.7 million of preferred units issued by HEP. (3) Includes a loss of $3.4 million for the nine months ended September 30, 2017 from the sale of our HEP interests. The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Gulf Coast Fractionators $ 46.4 $ 48.5 Howard Energy Partners — 193.1 Cedar Cove JV 39.7 28.8 Total investment in unconsolidated affiliates $ 86.1 $ 270.4

Employee Incentive Plans

Employee Incentive Plans	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Incentive Plans	(12) Employee Incentive Plans (a) Long-Term Incentive Plans ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “LLC Plan”) , and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”) . We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards be recognized on the consolidated financial statements. Unit-based compensation cost 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 our officers and employees is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK and EnLink Oklahoma T.O. 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 2017 2016 2017 2016 Cost of unit-based compensation charged to general and administrative expense $ 7.4 $ 5.8 $ 28.5 $ 17.7 Cost of unit-based compensation charged to operating expense 2.8 1.6 10.4 4.8 Total unit-based compensation expense $ 10.2 $ 7.4 $ 38.9 $ 22.5 Non-controlling interest in unit-based compensation $ 3.9 $ 2.7 $ 14.6 $ 8.3 Amount of related income tax benefit recognized in net income (1) $ 2.4 $ 1.7 $ 9.1 $ 5.4 (1) For the nine months ended September 30, 2017 , the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09. (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 the common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2017 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 2,024,820 $ 19.05 Granted (1) 859,595 18.41 Vested (1)(2) (851,753 ) 25.90 Forfeited (32,225 ) 16.28 Non-vested, end of period 2,000,437 $ 15.91 Aggregate intrinsic value, end of period (in millions) $ 33.5 (1) Restricted incentive units typically vest at the end of three years. In March 2017, ENLK granted 262,288 restricted incentive units with a fair value of $5.1 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 273,848 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, 2017 and 2016 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2017 2016 2017 2016 Aggregate intrinsic value of units vested $ 0.6 $ 0.3 $ 16.3 $ 4.1 Fair value of units vested $ 1.1 $ 0.5 $ 22.1 $ 9.5 As of September 30, 2017 , there was $14.6 million of unrecognized compensation cost related to non-vested ENLK restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.7 years . (c) EnLink Midstream Partners, LP Performance Units For the nine months ended September 30, 2017 , the General Partner and EnLink Midstream Manager, LLC, our managing member, granted performance awards under the GP Plan and the LLC Plan, respectively. The performance award agreements provide that the vesting of 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 Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding ENLC and ENLK (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLC’s and ENLK’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 range 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 ENLK’s common units and the designated peer group securities; (iii) an estimated ranking of ENLK among the designated peer group; 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 Partners, LP Performance Units: March 2017 Beginning TSR Price $ 17.55 Risk-free interest rate 1.62 % Volatility factor 43.94 % Distribution yield 8.7 % 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 408,637 $ 18.27 Granted 176,648 25.73 Forfeited — — Non-vested, end of period 585,285 $ 20.52 Aggregate intrinsic value, end of period (in millions) $ 9.8 As of September 30, 2017 , there was $5.9 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 1.9 years . (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 the ENLC common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2017 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 1,897,298 $ 19.96 Granted (1) 817,201 19.24 Vested (1)(2) (775,973 ) 28.28 Forfeited (31,636 ) 16.53 Non-vested, end of period 1,906,890 $ 16.32 Aggregate intrinsic value, end of period (in millions) $ 32.9 (1) Restricted incentive units typically vest at the end of three years. In March 2017, ENLC granted 258,606 restricted incentive units with a fair value of $5.0 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 238,312 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, 2017 and 2016 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream, LLC Restricted Incentive Units: 2017 2016 2017 2016 Aggregate intrinsic value of units vested $ 0.6 $ 0.3 $ 15.2 $ 4.1 Fair value of units vested $ 1.1 $ 0.6 $ 21.9 $ 12.4 As of September 30, 2017 , there was $14.2 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.8 years . (e) EnLink Midstream, LLC’s Performance Units For the nine months ended September 30, 2017 , ENLC granted performance awards under the LLC Plan. 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 range 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 group securities; (iii) an estimated ranking of ENLC among the designated peer group 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 2017 Beginning TSR Price $ 18.29 Risk-free interest rate 1.62 % Volatility factor 52.07 % Distribution yield 5.4 % 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 384,264 $ 19.30 Granted 164,575 28.77 Forfeited — — Non-vested, end of period 548,839 $ 22.14 Aggregate intrinsic value, end of period (in millions) $ 9.5 As of September 30, 2017 , 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 2.0 years .

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(13) 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 on the consolidated statements of operations. In May 2017, we entered into an interest rate swap in connection with the issuance of 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 other comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. We have no open interest rate swap positions as of September 30, 2017 . In addition, the settlement loss is included as an operating cash outflow on the consolidated statements of cash flows. For the three and nine months ended September 30, 2017 , 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. In July 2016, we entered into an interest rate swap in connection with ENLK’s issuance of its 4.85% senior unsecured notes due 2026. We did not designate this swap as a cash flow hedge. Upon settlement of the interest rate swap in July 2016, we recorded the associated $0.4 million gain on settlement in other income (expense) in the consolidated statements of operations for the three and nine months ended September 30, 2016 . Commodity Swaps We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used to manage and hedge price and location risk related to these market exposures. Commodity swaps are also used 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 swap transactions 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 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, 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. The components of gain (loss) on derivative activity on the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Change in fair value of derivatives $ (3.3 ) $ (1.6 ) $ 3.8 $ (16.0 ) Realized gain (loss) on derivatives (2.2 ) 1.1 (4.9 ) 9.4 Loss on derivative activity $ (5.5 ) $ (0.5 ) $ (1.1 ) $ (6.6 ) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): September 30, 2017 December 31, 2016 Fair value of derivative assets — current $ 4.6 $ 1.3 Fair value of derivative assets — long-term 0.1 — Fair value of derivative liabilities — current (7.2 ) (7.6 ) Net fair value of derivatives $ (2.5 ) $ (6.3 ) 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. 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, 2017 (in millions). The remaining term of the contracts extend no later than October 2018. September 30, 2017 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (35.8 ) $ (4.9 ) NGL (long contracts) Swaps Gallons 25.1 1.9 Natural Gas (short contracts) Swaps MMBtu (20.5 ) 1.3 Natural Gas (long contracts) Swaps MMBtu 23.2 (0.7 ) Condensate (short contracts) Swaps MMbbls 0.1 (0.1 ) Total fair value of derivatives $ (2.5 ) On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have entered into Master International Swaps and Derivatives Association Agreements (“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, our maximum loss of $4.7 million as of September 30, 2017 would be reduced to $1.7 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, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	(14) 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, 2017 December 31, 2016 Commodity Swaps (1) $ (2.5 ) $ (6.3 ) Total $ (2.5 ) $ (6.3 ) (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, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 3,540.5 $ 3,638.7 $ 3,295.3 $ 3,253.6 Installment Payables $ 243.0 $ 243.7 $ 473.2 $ 476.6 Obligations under capital lease $ 4.4 $ 3.7 $ 6.6 $ 6.1 (1) The carrying value of long-term debt is reduced by debt issuance costs of $27.2 million and $24.6 million at September 30, 2017 and December 31, 2016 , 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. ENLK had no outstanding borrowings under the ENLK Credit Facility as of September 30, 2017 and $120.0 million of outstanding borrowings under the ENLK Credit Facility as of December 31, 2016 . ENLC had $74.0 million and $27.8 million in outstanding borrowings under the ENLC Credit Facility as of September 30, 2017 and December 31, 2016 , respectively. As borrowings under the credit facilities accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facilities. As of September 30, 2017 and December 31, 2016 , ENLK had total borrowings under senior unsecured notes of $3.5 billion and $3.1 billion , respectively, maturing between 2019 and 2047 with fixed interest rates ranging from 2.7% to 5.6% and 2.7% to 7.1% , respectively. The fair values of all senior unsecured notes and installment payables as of September 30, 2017 and December 31, 2016 were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases were calculated using Level 2 inputs from third-party banks.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies (a) Severance and Change in Control Agreements Certain members of our management are parties to severance and change of control agreements with EnLink Midstream Operating, LP. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or its affiliates or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment. (b) Environmental Issues The operation of pipelines, plants and other facilities for the gathering, processing, transmitting, stabilizing, fractionating, storing or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner, partner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, oil spill prevention, climate change, endangered species and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must account for compliance with environmental laws and regulations and safety standards. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows. However, we cannot provide assurance that future events, such as changes in existing laws, regulations, or enforcement policies, the promulgation of new laws or regulations, or the discovery or development of new factual circumstances will not cause us to incur material costs. Environmental regulations have historically become more stringent over time and, thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation. In the second quarter of 2017, we reached a settlement agreement with the Ohio Environmental Protection Agency with respect to the previously disclosed notices of violation (“NOVs”) relating to certain of our ORV operations that were previously operated by a joint venture partner. The settlement payment is not material to our results of operations, financial condition or cash flows. On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of our Louisiana operations, we commenced discussions with the Louisiana Department of Environmental Quality (“LDEQ”) relating to: (a) a global settlement to resolve environmental noncompliance discovered or investigated during our assessment involving several of our Louisiana facilities and (b) notices of potential violation and NOVs received from the LDEQ. We have taken appropriate measures to resolve all instances of noncompliance. In the third quarter of 2017, we reached a global settlement with the LDEQ pursuant to which we paid approximately $0.3 million . As part of our ongoing environmental and regulatory compliance efforts, we discovered instances of non-compliance with certain environmental regulations at one of our north Texas plants and self-reported these matters to the Texas Commission on Environment Quality (“TCEQ”). On October 4, 2017, we received and accepted an Agreed Order from the TCEQ related to these instances of non-compliance. The final penalty assessed was not material to the results of our operations, financial condition or cash flows. Finally, we continue to await a ruling from the Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the year ended December 31, 2016. (c) Litigation Contingencies We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows. In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. Our subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs appealed the matter to the United States Court of Appeals for the Fifth Circuit. On March 3, 2017, the Court of Appeals affirmed the district court’s dismissal of the plaintiff’s claims. On March 17, 2017, the plaintiff filed a petition for rehearing. On April 12, 2017, the Court of Appeals denied the plaintiffs petition for rehearing. On July 11, 2017, the plaintiffs filed a petition for appeal with the United States Supreme Court, which was denied on October 30, 2017. We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern in the area, and its insurers, seeking recovery for these losses, as well as other parties we alleged contributed to the formation of the sinkhole. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers. We have reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million . We secured additional settlement payments in aggregate amounts of $17.5 million and $8.5 million in March 2017 and June 2017, respectively, which resulted in the recognition of “Gain on litigation settlement” on the consolidated statements of operations of $26.0 million for the nine months ended September 30, 2017 . In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit in the 23rd Judicial Court, Assumption Parish, Louisiana they had filed against other defendants relating to claims arising from the Bayou Corne Sinkhole. Plaintiffs alleged that EnLink Processing Services, LLC’s negligence contributed to the formation of the sinkhole. The amount of damages was unspecified. EnLink Processing Services, LLC reached a settlement with the plaintiffs in February 2017, funded by EnLink Processing Services, LLC’s insurance carriers. The plaintiffs’ claims against EnLink Processing Services, LLC were dismissed with prejudice in March 2017.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information	(16) 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 Midland and Delaware basins in west Texas (“Texas”), the pipelines, processing plants, storage facilities and NGL 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 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 operating revenues and segment profits. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and unconsolidated affiliate investments in GCF and the Cedar Cove JV as of September 30, 2017 and December 31, 2016. As of December 31, 2016, our Corporate assets included our unconsolidated affiliate investment in HEP. In December 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale in March 2017. 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, 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 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 39.1 $ 7.5 $ 107.7 $ 13.3 $ 2.1 $ 169.7 Three Months Ended September 30, 2016 Product sales $ 61.3 $ 430.9 $ 16.2 $ 262.6 $ — $ 771.0 Product sales—related parties 81.9 24.4 36.0 — (99.2 ) 43.1 Midstream services 27.5 57.2 24.2 16.8 — 125.7 Midstream services—related parties 109.5 29.9 47.7 5.2 (27.0 ) 165.3 Cost of sales (134.1 ) (471.5 ) (58.3 ) (250.5 ) 126.2 (788.2 ) Operating expenses (42.9 ) (23.5 ) (12.6 ) (19.0 ) — (98.0 ) Loss on derivative activity — — — — (0.5 ) (0.5 ) Segment profit (loss) $ 103.2 $ 47.4 $ 53.2 $ 15.1 $ (0.5 ) $ 218.4 Depreciation and amortization $ (48.7 ) $ (28.8 ) $ (35.6 ) $ (10.7 ) $ (2.4 ) $ (126.2 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 51.8 $ 15.4 $ 58.3 $ 12.8 $ 8.6 $ 146.9 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals 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 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 107.1 $ 55.8 $ 383.4 $ 64.4 $ 25.6 $ 636.3 Nine Months Ended September 30, 2016 Product sales $ 165.7 $ 1,118.1 $ 32.9 $ 781.1 $ — $ 2,097.8 Product sales—related parties 191.9 47.0 69.1 1.1 (209.8 ) 99.3 Midstream services 78.1 165.1 57.3 48.0 — 348.5 Midstream services—related parties 331.7 68.1 134.4 14.4 (60.1 ) 488.5 Cost of sales (329.0 ) (1,199.1 ) (109.2 ) (739.4 ) 269.9 (2,106.8 ) Operating expenses (125.2 ) (72.2 ) (37.2 ) (61.7 ) — (296.3 ) Loss on derivative activity — — — — (6.6 ) (6.6 ) Segment profit (loss) $ 313.2 $ 127.0 $ 147.3 $ 43.5 $ (6.6 ) $ 624.4 Depreciation and amortization $ (143.6 ) $ (86.7 ) $ (104.2 ) $ (31.7 ) $ (6.8 ) $ (373.0 ) Impairments $ (473.1 ) $ — $ — $ (93.2 ) $ (307.0 ) $ (873.3 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 132.3 $ 52.2 $ 190.6 $ 17.0 $ 15.4 $ 407.5 The table below represents information about segment assets as of September 30, 2017 and December 31, 2016 (in millions): Segment Identifiable Assets: September 30, 2017 December 31, 2016 Texas $ 3,113.0 $ 3,142.6 Louisiana 2,395.5 2,349.3 Oklahoma 2,814.7 2,524.5 Crude and Condensate 847.2 836.8 Corporate 1,377.9 1,422.7 Total identifiable assets $ 10,548.3 $ 10,275.9 The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Segment profits $ 242.6 $ 218.4 $ 686.7 $ 624.4 General and administrative expenses (31.3 ) (29.3 ) (98.5 ) (94.7 ) Gain (loss) on disposition of assets (1.1 ) 3.0 (0.8 ) 2.9 Depreciation and amortization (136.3 ) (126.2 ) (407.1 ) (373.0 ) Impairments (1.8 ) — (8.8 ) (873.3 ) Gain on litigation settlement — — 26.0 — Operating income (loss) $ 72.1 $ 65.9 $ 197.5 $ (713.7 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(17) Supplemental Cash Flow Information The following schedule summarizes non-cash financing activities for the periods presented (in millions): Nine Months Ended September 30, 2017 2016 Non-cash financing activities: Non-cash issuance of ENLC common units (1) $ — $ 214.9 Installment payable, net of discount of $79.1 million (2) — 420.9 (1) Non-cash ENLC common units were issued as partial consideration for the acquisition of EnLink Oklahoma T.O. assets. See “ Note 3—Acquisition ” for further discussion. (2) ENLK incurred installment purchase obligations, net of discount, payable to the seller in connection with the EnLink Oklahoma T.O. assets. ENLK paid the first installment on January 6, 2017 and will pay the final installment no later than January 7, 2018. See “ Note 3—Acquisition ” for further discussion.

Other Information

Other Information	9 Months Ended
	Sep. 30, 2017
Other Liabilities Disclosure [Abstract]
Other Information	(18) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): September 30, 2017 December 31, 2016 Natural gas and NGLs inventory $ 59.1 $ 17.4 Prepaid expenses and other 14.3 16.1 Natural gas and NGLs inventory, prepaid expenses and other $ 73.4 $ 33.5 September 30, 2017 December 31, 2016 Accrued interest $ 64.8 $ 34.2 Accrued wages and benefits, including taxes 23.2 19.0 Accrued ad valorem taxes 33.5 23.5 Capital expenditure accruals 43.6 64.6 Onerous performance obligations 15.4 15.9 Other 54.7 60.3 Other current liabilities $ 235.2 $ 217.5

Significant Accounting Polici28

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
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 generally accepted accounting principles in the United States of America (“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.
Adopted Accounting Standards; Accounting Standards to be Adopted in Future Periods	Adopted Accounting Standards In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which simplifies several aspects related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adopted the guidance that requires excess tax benefits and deficiencies be recognized on the income statement. The cash flow statement guidance requires the presentation of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of the new guidance did not materially affect the consolidated statements of operations for the three and nine months ended September 30, 2017 . In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350) — Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, Intangibles — Goodwill and Other (“ASC 350”). As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04. (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”). 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. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheets 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 addition, there are industry-specific concerns with the implementation of ASU 2016-02, including the application of ASU 2016-02 to contracts involving easements/right-of-ways, which will require further evaluation before we are able to fully assess the impact on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require 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 will also require 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. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018. We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer from our customer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. 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 will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time 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 will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. This reclassification of revenues and costs will have no effect on operating income. Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, ASC 606 will not significantly affect the timing of income and expense on the statement of operations, and we will continue to recognize revenue at the time commodities are delivered or services are performed. Based on the disclosure requirements of ASC 606, upon adoption, we expect to provide expanded disclosures relating to our revenue recognition policies and how these relate to our revenue-generating contractual performance obligations. In addition, we expect to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues.
Property and Equipment	Property & Equipment Impairment Review. We evaluate our property and equipment 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.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is composed of net income (loss) and other comprehensive income (loss), which consists of the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”).

Acquisition (Tables)

Acquisition (Tables)	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Schedule of Consideration and Fair Value of Identified Assets Received and Liabilities Assumed	The following table presents the consideration ENLC and ENLK paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration: Cash $ 805.8 Issuance of ENLC common units 214.9 ENLK’s total installment payable, net of discount of $79.1 million assuming payments made on January 7, 2017 and 2018 420.9 Total consideration $ 1,441.6 Purchase Price Allocation: Assets acquired: Current assets (including $12.8 million in cash) $ 23.0 Property, plant and equipment 406.1 Intangibles 1,051.3 Liabilities assumed: Current liabilities (38.8 ) Total identifiable net assets $ 1,441.6

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Changes in Carrying Value	The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Nine Months Ended September 30, 2017 Customer relationships, beginning of period $ 1,795.8 $ (171.6 ) $ 1,624.2 Amortization expense — (96.2 ) (96.2 ) Customer relationships, end of period $ 1,795.8 $ (267.8 ) $ 1,528.0
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2017 (remaining) $ 30.8 2018 123.4 2019 123.4 2020 123.4 2021 123.4 Thereafter 1,003.6 Total $ 1,528.0

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Summary of Debt	As of September 30, 2017 and December 31, 2016 , long-term debt consisted of the following (in millions): September 30, 2017 December 31, 2016 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt ENLK credit facility due 2020 (1) $ — $ — $ — $ 120.0 $ — $ 120.0 ENLC credit facility due 2019 (2) 74.0 — 74.0 27.8 — 27.8 2.70% Senior unsecured notes due 2019 400.0 (0.2 ) 399.8 400.0 (0.3 ) 399.7 7.125% Senior unsecured notes due 2022 — — — 162.5 16.0 178.5 4.40% Senior unsecured notes due 2024 550.0 2.3 552.3 550.0 2.5 552.5 4.15% Senior unsecured notes due 2025 750.0 (1.0 ) 749.0 750.0 (1.1 ) 748.9 4.85% Senior unsecured notes due 2026 500.0 (0.6 ) 499.4 500.0 (0.7 ) 499.3 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 (6.5 ) 443.5 450.0 (6.6 ) 443.4 5.45% Senior unsecured notes due 2047 500.0 (0.1 ) 499.9 — — — Debt classified as long-term $ 3,574.0 $ (6.3 ) $ 3,567.7 $ 3,310.3 $ 9.6 $ 3,319.9 Debt issuance cost (3) (27.2 ) (24.6 ) Long-term debt, net of unamortized issuance cost $ 3,540.5 $ 3,295.3 (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% at December 31, 2016 . (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.2% and 3.4% at September 30, 2017 and December 31, 2016 , respectively. (3) Net of amortization of $11.9 million and $9.0 million at September 30, 2017 and December 31, 2016 , respectively.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income taxes included on the consolidated financial statements were as follows for the periods presented (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 ENLC income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0 Total income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles total income tax expense (benefit) and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Tax expense (benefit) at statutory federal rate (35%) $ 3.3 $ 2.0 $ 6.8 $ (158.0 ) State income taxes expense (benefit), net of federal tax benefit 0.2 3.1 0.5 (11.8 ) Income tax expense from partnership 0.5 2.6 0.7 1.3 Unit-based compensation (1) — — 2.3 — Non-deductible expense related to asset impairment — (0.1 ) — 173.8 Other (0.9 ) — (1.0 ) 0.7 Total income tax expense $ 3.1 $ 7.6 $ 9.3 $ 6.0 (1) Related to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.

Certain Provisions of the Par33

Certain Provisions of the Partnership Agreement (Tables)	9 Months Ended
	Sep. 30, 2017
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of ENLK’s distribution activity relating to the common units for the nine months ended September 30, 2017 and 2016 is provided below: Declaration period Distribution/unit Date paid/payable 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 2016 Fourth Quarter of 2015 $ 0.39 February 11, 2016 First Quarter of 2016 $ 0.39 May 12, 2016 Second Quarter of 2016 $ 0.39 August 11, 2016 Third Quarter of 2016 $ 0.39 November 11, 2016 A summary of the distribution activity relating to the Series B Preferred Units for the nine months ended September 30, 2017 and 2016 is provided below: Declaration period Distribution paid-in kind (1) Cash Distribution (in millions) Date paid/payable 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 2016 First Quarter of 2016 992,445 $ — May 12, 2016 Second Quarter of 2016 1,083,589 $ — August 11, 2016 Third Quarter of 2016 1,106,616 $ — November 10, 2016 (1) Represents distributions paid or payable on the Series B Preferred Units through issuance of additional Series B Preferred Units.
Incentive Distributions	The net income allocated to the General Partner is as follows (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Income allocation for incentive distributions $ 14.8 $ 14.4 $ 44.1 $ 42.4 Unit-based compensation attributable to ENLC’s restricted units (4.2 ) (3.6 ) (16.9 ) (11.2 ) General Partner share of net income (loss) — — 0.1 (2.4 ) General Partner interest in net income $ 10.6 $ 10.8 $ 27.3 $ 28.8

Members' Equity (Tables)

Members' Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings per Limited Partner Unit	The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions, except per unit amounts): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 EnLink Midstream, LLC interest in net income (loss) $ 6.2 $ 0.7 $ 10.2 $ (456.1 ) Distributed earnings allocated to: Common units (1) (2) $ 46.0 $ 45.9 $ 138.0 $ 137.4 Unvested restricted units (1) (2) 0.7 0.6 1.9 1.6 Total distributed earnings $ 46.7 $ 46.5 $ 139.9 $ 139.0 Undistributed loss allocated to: Common units $ (39.9 ) $ (45.1 ) $ (128.0 ) $ (588.3 ) Unvested restricted units (0.6 ) (0.7 ) (1.7 ) (6.8 ) Total undistributed loss $ (40.5 ) $ (45.8 ) $ (129.7 ) $ (595.1 ) Net income (loss) allocated to: Common units $ 6.1 $ 0.8 $ 10.0 $ (450.9 ) Unvested restricted units 0.1 (0.1 ) 0.2 (5.2 ) Total net income (loss) $ 6.2 $ 0.7 $ 10.2 $ (456.1 ) Basic and diluted net income (loss) per unit: Basic $ 0.03 $ — $ 0.06 $ (2.54 ) Diluted $ 0.03 $ — $ 0.06 $ (2.54 ) (1) For the three months ended September 30, 2017 and 2016 , distributed earnings included a declared distribution of $0.255 per unit payable on November 14, 2017 and a distribution of $0.255 per unit paid on November 14, 2016 , respectively. (2) For the nine months ended September 30, 2017 , distributed earnings included distributions of $0.255 per unit paid on May 15, 2017 and August 14, 2017 and a declared distribution of $0.255 per unit payable on November 14, 2017 . For the nine months ended September 30, 2016 , distributed earnings included distributions of $0.255 per unit paid on May 13, 2016 , $0.255 per unit paid on August 12, 2016 , and $0.255 per unit paid on November 14, 2016 .
Schedule of Unit Amounts Used to Computer Earnings per Unit	The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Basic and diluted earnings per unit: Weighted average common units outstanding 180.6 180.0 180.4 179.6 Diluted weighted average units outstanding: Weighted average basic common units outstanding 180.6 180.0 180.4 179.6 Dilutive effect of non-vested restricted incentive units (1) 1.2 1.1 1.3 — Total weighted average diluted common units outstanding 181.8 181.1 181.7 179.6 (1) For the nine months ended September 30, 2016 , all common unit equivalents were antidilutive since a net loss existed for that period.
Summary of Distribution Activity	A summary of our distribution activity relating to the ENLC common units for the nine months ended September 30, 2017 and 2016 , respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2017 Fourth Quarter of 2016 $ 0.255 February 14, 2017 First Quarter of 2017 $ 0.255 May 15, 2017 Second Quarter 2017 $ 0.255 August 14, 2017 Third Quarter 2017 $ 0.255 November 14, 2017 2016 Fourth Quarter of 2015 $ 0.255 February 12, 2016 First Quarter of 2016 $ 0.255 May 13, 2016 Second Quarter 2016 $ 0.255 August 12, 2016 Third Quarter 2016 $ 0.255 November 14, 2016

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The schedule below summarizes the changes in our asset retirement obligations (in millions): Nine Months Ended September 30, 2017 Balance, beginning of period $ 13.5 Accretion expense 0.5 Balance, end of period $ 14.0

Investment in Unconsolidated 36

Investment in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Gulf Coast Fractionators Contributions $ — $ — $ — $ — Distributions $ 3.5 $ 0.9 $ 10.6 $ 4.4 Equity in income $ 4.5 $ 2.2 $ 8.5 $ 1.1 Howard Energy Partners Contributions (1) $ — $ 3.2 $ — $ 45.0 Distributions (2) $ — $ 36.5 $ — $ 47.9 Equity in loss (3) $ — $ (1.1 ) $ (3.4 ) $ (1.6 ) Cedar Cove JV Contributions $ 1.5 $ — $ 11.8 $ — Distributions $ 0.5 $ — $ 0.8 $ — Equity in loss $ (0.1 ) $ — $ (0.1 ) $ — Total Contributions (1) $ 1.5 $ 3.2 $ 11.8 $ 45.0 Distributions (2) $ 4.0 $ 37.4 $ 11.4 $ 52.3 Equity in income (loss) (3) $ 4.4 $ 1.1 $ 5.0 $ (0.5 ) (1) Contributions for the three and nine months ended September 30, 2016 included $3.2 million and $32.7 million , respectively, of contributions to HEP for preferred units issued by HEP, which were redeemed during the third quarter of 2016. (2) Distributions for the three and nine months ended September 30, 2016 included a redemption of $32.7 million of preferred units issued by HEP. (3) Includes a loss of $3.4 million for the nine months ended September 30, 2017 from the sale of our HEP interests. The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2017 and December 31, 2016 (in millions): September 30, 2017 December 31, 2016 Gulf Coast Fractionators $ 46.4 $ 48.5 Howard Energy Partners — 193.1 Cedar Cove JV 39.7 28.8 Total investment in unconsolidated affiliates $ 86.1 $ 270.4

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 2017
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 2017 2016 2017 2016 Cost of unit-based compensation charged to general and administrative expense $ 7.4 $ 5.8 $ 28.5 $ 17.7 Cost of unit-based compensation charged to operating expense 2.8 1.6 10.4 4.8 Total unit-based compensation expense $ 10.2 $ 7.4 $ 38.9 $ 22.5 Non-controlling interest in unit-based compensation $ 3.9 $ 2.7 $ 14.6 $ 8.3 Amount of related income tax benefit recognized in net income (1) $ 2.4 $ 1.7 $ 9.1 $ 5.4 (1) For the nine months ended September 30, 2017 , the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.
Summary of Restricted Incentive Unit Activity	A summary of the restricted incentive unit activity for the nine months ended September 30, 2017 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 2,024,820 $ 19.05 Granted (1) 859,595 18.41 Vested (1)(2) (851,753 ) 25.90 Forfeited (32,225 ) 16.28 Non-vested, end of period 2,000,437 $ 15.91 Aggregate intrinsic value, end of period (in millions) $ 33.5 (1) Restricted incentive units typically vest at the end of three years. In March 2017, ENLK granted 262,288 restricted incentive units with a fair value of $5.1 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 273,848 units withheld for payroll taxes paid on behalf of employees. Nine Months Ended EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,897,298 $ 19.96 Granted (1) 817,201 19.24 Vested (1)(2) (775,973 ) 28.28 Forfeited (31,636 ) 16.53 Non-vested, end of period 1,906,890 $ 16.32 Aggregate intrinsic value, end of period (in millions) $ 32.9 (1) Restricted incentive units typically vest at the end of three years. In March 2017, ENLC granted 258,606 restricted incentive units with a fair value of $5.0 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 238,312 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, 2017 and 2016 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream, LLC Restricted Incentive Units: 2017 2016 2017 2016 Aggregate intrinsic value of units vested $ 0.6 $ 0.3 $ 15.2 $ 4.1 Fair value of units vested $ 1.1 $ 0.6 $ 21.9 $ 12.4 A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, 2017 and 2016 is provided below (in millions): Three Months Ended September 30, Nine Months Ended September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2017 2016 2017 2016 Aggregate intrinsic value of units vested $ 0.6 $ 0.3 $ 16.3 $ 4.1 Fair value of units vested $ 1.1 $ 0.5 $ 22.1 $ 9.5
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream, LLC Performance Units: March 2017 Beginning TSR Price $ 18.29 Risk-free interest rate 1.62 % Volatility factor 52.07 % Distribution yield 5.4 % The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: EnLink Midstream Partners, LP Performance Units: March 2017 Beginning TSR Price $ 17.55 Risk-free interest rate 1.62 % Volatility factor 43.94 % Distribution yield 8.7 %
Summary of Performance Units	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 384,264 $ 19.30 Granted 164,575 28.77 Forfeited — — Non-vested, end of period 548,839 $ 22.14 Aggregate intrinsic value, end of period (in millions) $ 9.5 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 408,637 $ 18.27 Granted 176,648 25.73 Forfeited — — Non-vested, end of period 585,285 $ 20.52 Aggregate intrinsic value, end of period (in millions) $ 9.8

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of gain (loss) on derivative activity on the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Change in fair value of derivatives $ (3.3 ) $ (1.6 ) $ 3.8 $ (16.0 ) Realized gain (loss) on derivatives (2.2 ) 1.1 (4.9 ) 9.4 Loss on derivative activity $ (5.5 ) $ (0.5 ) $ (1.1 ) $ (6.6 )
Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps	The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): September 30, 2017 December 31, 2016 Fair value of derivative assets — current $ 4.6 $ 1.3 Fair value of derivative assets — long-term 0.1 — Fair value of derivative liabilities — current (7.2 ) (7.6 ) Net fair value of derivatives $ (2.5 ) $ (6.3 )
Notional Amount and Fair Value of Derivative Instruments	Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at September 30, 2017 (in millions). The remaining term of the contracts extend no later than October 2018. September 30, 2017 Commodity Instruments Unit Volume Fair Value NGL (short contracts) Swaps Gallons (35.8 ) $ (4.9 ) NGL (long contracts) Swaps Gallons 25.1 1.9 Natural Gas (short contracts) Swaps MMBtu (20.5 ) 1.3 Natural Gas (long contracts) Swaps MMBtu 23.2 (0.7 ) Condensate (short contracts) Swaps MMbbls 0.1 (0.1 ) Total fair value of derivatives $ (2.5 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
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, 2017 December 31, 2016 Commodity Swaps (1) $ (2.5 ) $ (6.3 ) Total $ (2.5 ) $ (6.3 ) (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.
Schedule of the Estimated Fair Value of Financial Instruments	September 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value Long-term debt (1) $ 3,540.5 $ 3,638.7 $ 3,295.3 $ 3,253.6 Installment Payables $ 243.0 $ 243.7 $ 473.2 $ 476.6 Obligations under capital lease $ 4.4 $ 3.7 $ 6.6 $ 6.1 (1) The carrying value of long-term debt is reduced by debt issuance costs of $27.2 million and $24.6 million at September 30, 2017 and December 31, 2016 , respectively. The respective fair values do not factor in debt issuance costs.

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Summary of 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, 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 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 39.1 $ 7.5 $ 107.7 $ 13.3 $ 2.1 $ 169.7 Three Months Ended September 30, 2016 Product sales $ 61.3 $ 430.9 $ 16.2 $ 262.6 $ — $ 771.0 Product sales—related parties 81.9 24.4 36.0 — (99.2 ) 43.1 Midstream services 27.5 57.2 24.2 16.8 — 125.7 Midstream services—related parties 109.5 29.9 47.7 5.2 (27.0 ) 165.3 Cost of sales (134.1 ) (471.5 ) (58.3 ) (250.5 ) 126.2 (788.2 ) Operating expenses (42.9 ) (23.5 ) (12.6 ) (19.0 ) — (98.0 ) Loss on derivative activity — — — — (0.5 ) (0.5 ) Segment profit (loss) $ 103.2 $ 47.4 $ 53.2 $ 15.1 $ (0.5 ) $ 218.4 Depreciation and amortization $ (48.7 ) $ (28.8 ) $ (35.6 ) $ (10.7 ) $ (2.4 ) $ (126.2 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 51.8 $ 15.4 $ 58.3 $ 12.8 $ 8.6 $ 146.9 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals 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 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 107.1 $ 55.8 $ 383.4 $ 64.4 $ 25.6 $ 636.3 Nine Months Ended September 30, 2016 Product sales $ 165.7 $ 1,118.1 $ 32.9 $ 781.1 $ — $ 2,097.8 Product sales—related parties 191.9 47.0 69.1 1.1 (209.8 ) 99.3 Midstream services 78.1 165.1 57.3 48.0 — 348.5 Midstream services—related parties 331.7 68.1 134.4 14.4 (60.1 ) 488.5 Cost of sales (329.0 ) (1,199.1 ) (109.2 ) (739.4 ) 269.9 (2,106.8 ) Operating expenses (125.2 ) (72.2 ) (37.2 ) (61.7 ) — (296.3 ) Loss on derivative activity — — — — (6.6 ) (6.6 ) Segment profit (loss) $ 313.2 $ 127.0 $ 147.3 $ 43.5 $ (6.6 ) $ 624.4 Depreciation and amortization $ (143.6 ) $ (86.7 ) $ (104.2 ) $ (31.7 ) $ (6.8 ) $ (373.0 ) Impairments $ (473.1 ) $ — $ — $ (93.2 ) $ (307.0 ) $ (873.3 ) Goodwill $ 232.0 $ — $ 190.3 $ — $ 1,119.9 $ 1,542.2 Capital expenditures $ 132.3 $ 52.2 $ 190.6 $ 17.0 $ 15.4 $ 407.5
Schedule of Segment Assets	The table below represents information about segment assets as of September 30, 2017 and December 31, 2016 (in millions): Segment Identifiable Assets: September 30, 2017 December 31, 2016 Texas $ 3,113.0 $ 3,142.6 Louisiana 2,395.5 2,349.3 Oklahoma 2,814.7 2,524.5 Crude and Condensate 847.2 836.8 Corporate 1,377.9 1,422.7 Total identifiable assets $ 10,548.3 $ 10,275.9
Reconciliation of Profits to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Segment profits $ 242.6 $ 218.4 $ 686.7 $ 624.4 General and administrative expenses (31.3 ) (29.3 ) (98.5 ) (94.7 ) Gain (loss) on disposition of assets (1.1 ) 3.0 (0.8 ) 2.9 Depreciation and amortization (136.3 ) (126.2 ) (407.1 ) (373.0 ) Impairments (1.8 ) — (8.8 ) (873.3 ) Gain on litigation settlement — — 26.0 — Operating income (loss) $ 72.1 $ 65.9 $ 197.5 $ (713.7 )

Supplemental Cash Flow Inform41

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Summary of Non-Cash Financing Activities	The following schedule summarizes non-cash financing activities for the periods presented (in millions): Nine Months Ended September 30, 2017 2016 Non-cash financing activities: Non-cash issuance of ENLC common units (1) $ — $ 214.9 Installment payable, net of discount of $79.1 million (2) — 420.9 (1) Non-cash ENLC common units were issued as partial consideration for the acquisition of EnLink Oklahoma T.O. assets. See “ Note 3—Acquisition ” for further discussion. (2) ENLK incurred installment purchase obligations, net of discount, payable to the seller in connection with the EnLink Oklahoma T.O. assets. ENLK paid the first installment on January 6, 2017 and will pay the final installment no later than January 7, 2018. See “ Note 3—Acquisition ” for further discussion.

Other Information (Tables)

Other Information (Tables)	9 Months Ended
	Sep. 30, 2017
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): September 30, 2017 December 31, 2016 Natural gas and NGLs inventory $ 59.1 $ 17.4 Prepaid expenses and other 14.3 16.1 Natural gas and NGLs inventory, prepaid expenses and other $ 73.4 $ 33.5 September 30, 2017 December 31, 2016 Accrued interest $ 64.8 $ 34.2 Accrued wages and benefits, including taxes 23.2 19.0 Accrued ad valorem taxes 33.5 23.5 Capital expenditure accruals 43.6 64.6 Onerous performance obligations 15.4 15.9 Other 54.7 60.3 Other current liabilities $ 235.2 $ 217.5

General (Details)

General (Details)	9 Months Ended
	Sep. 30, 2017shares
EnLink Midstream Partners, LP
Related Party Transaction [Line Items]
Units owned, limited partner interest (in shares)	88,528,451
Ownership interest	21.80%
Membership interest in the General Partner	0.40%
EnLink Midstream Partners GP, LLC
Related Party Transaction [Line Items]
Ownership interest	100.00%
EnLink Oklahoma T.O.
Related Party Transaction [Line Items]
Ownership interest	16.00%

Significant Accounting Polici44

Significant Accounting Policies (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Expired rights-of-ways and abandoned brine disposal well
Property, Plant and Equipment [Line Items]
Impairment of long-lived assets	$ 8.8

Acquisition - Narrative (Detail

Acquisition - Narrative (Details) - USD ($) $ in Millions	Jan. 06, 2017	Jan. 07, 2016	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Business Acquisition [Line Items]
Common units issued (in shares)				180,586,977		180,049,316
EnLink Oklahoma T.O.
Business Acquisition [Line Items]
Acquired voting interest		16.00%
Consideration		$ 1,441.6
First installment		1,020
Payment of second installment	$ 250
Final installment payable				$ 250
Cash		$ 805.8
Common units issued (in shares)		15,564,009
Cash		$ 22.2
Estimated life of acquired intangible assets		15 years
Direct transaction costs			$ 4.8		$ 4.8
Direct transaction costs recognized as expense					4.4
Recognized revenue			77.3		149.5
Net gain (loss) related to assets acquired			$ (4.4)		$ (27.9)
EnLink Oklahoma T.O. | EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Acquired voting interest		84.00%
Cash		$ 783.6

Acquisition - Schedule of Consi

Acquisition - Schedule of Consideration, Assets and Liabilities (Details) - EnLink Oklahoma T.O. $ in Millions	Jan. 07, 2016USD ($)
Business Combination, Consideration Transferred [Abstract]
Cash	$ 805.8
Issuance of ENLC common units	214.9
Total consideration	1,441.6
Assets acquired:
Current assets (including $12.8 million in cash)	23
Cash acquired	12.8
Property, plant and equipment	406.1
Intangibles	1,051.3
Liabilities assumed:
Current liabilities	(38.8)
Total identifiable net assets	1,441.6
EnLink Midstream LP
Business Combination, Consideration Transferred [Abstract]
ENLK’s total installment payable, net of discount of $79.1 million assuming payments made on January 7, 2017 and 2018	420.9
Installment payable discount	$ 79.1

Goodwill and Intangible Asset47

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2016
Finite-Lived Intangible Assets [Line Items]
Goodwill impairment loss recognized			$ 873.3
Amortization expense	$ 31.2	$ 29.9		$ 96.2	$ 87.4
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				15 years

Goodwill and Intangible Asset48

Goodwill and Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance			$ (171.6)
Accumulated Amortization, Amortization expense	$ (31.2)	$ (29.9)	(96.2)	$ (87.4)
Accumulated Amortization, Ending Balance	(267.8)		(267.8)
EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Net Carrying Amount, Ending Balance	1,528		1,528
Customer relationships | EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			1,795.8
Accumulated Amortization, Beginning Balance			(171.6)
Net Carrying Amount, Beginning Balance			1,624.2
Accumulated Amortization, Amortization expense			(96.2)
Gross Carrying Amount, Ending Balance	1,795.8		1,795.8
Accumulated Amortization, Ending Balance	(267.8)		(267.8)
Net Carrying Amount, Ending Balance	$ 1,528		$ 1,528

Goodwill and Intangible Asset49

Goodwill and Intangible Assets - Amortization Expense (Details) - EnLink Midstream Partners, LP $ in Millions	Sep. 30, 2017USD ($)
Finite-Lived Intangible Assets [Line Items]
2017 (remaining)	$ 30.8
2,018	123.4
2,019	123.4
2,020	123.4
2,021	123.4
Thereafter	1,003.6
Total	$ 1,528

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Accounts payable to related party	$ 36.8		$ 36.8		$ 10.4
Devon Energy Corporation
Related Party Transaction [Line Items]
Accounts receivable balance	121.5		121.5		100.2
Accounts payable to related party	$ 36.8		$ 36.8		$ 10.4
Devon Energy Corporation | Customer Concentration Risk | Sales Revenue, Net
Related Party Transaction [Line Items]
Concentration risk	15.00%	18.90%	15.40%	19.40%

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($)	Sep. 30, 2017	May 11, 2017	Dec. 31, 2016
Debt Instrument
Outstanding Principal	$ 3,574,000,000		$ 3,310,300,000
Premium (Discount)	(6,300,000)		9,600,000
Long-Term Debt	3,567,700,000		3,319,900,000
Debt issuance costs	(27,200,000)		(24,600,000)
Long-term debt, net of unamortized issuance cost	3,540,500,000		$ 3,295,300,000
Effective interest rate			2.30%
Debt issuance cost accumulated amortization	11,900,000		$ 9,000,000
ENLK credit facility due 2020 | EnLink Midstream Partners, LP
Debt Instrument
Outstanding Principal	0		120,000,000
Premium (Discount)	0		0
Long-Term Debt	0		120,000,000
ENLC credit facility due 2019
Debt Instrument
Outstanding Principal	74,000,000		27,800,000
Premium (Discount)	0		0
Long-Term Debt	$ 74,000,000		$ 27,800,000
Effective interest rate	3.20%		3.40%
2.70% Senior unsecured notes due 2019
Debt Instrument
Stated interest rate	2.70%
Outstanding Principal	$ 400,000,000		$ 400,000,000
Premium (Discount)	(200,000)		(300,000)
Long-Term Debt	$ 399,800,000		399,700,000
7.125% Senior unsecured notes due 2022
Debt Instrument
Stated interest rate	7.125%
Outstanding Principal	$ 0		162,500,000
Premium (Discount)	0		16,000,000
Long-Term Debt	$ 0		178,500,000
4.40% Senior unsecured notes due 2024
Debt Instrument
Stated interest rate	4.40%
Outstanding Principal	$ 550,000,000		550,000,000
Premium (Discount)	2,300,000		2,500,000
Long-Term Debt	$ 552,300,000		552,500,000
4.15% Senior unsecured notes due 2025
Debt Instrument
Stated interest rate	4.15%
Outstanding Principal	$ 750,000,000		750,000,000
Premium (Discount)	(1,000,000)		(1,100,000)
Long-Term Debt	$ 749,000,000		748,900,000
4.85% Senior unsecured notes due 2026 | EnLink Midstream Partners, LP
Debt Instrument
Stated interest rate	4.85%
Outstanding Principal	$ 500,000,000		500,000,000
Premium (Discount)	(600,000)		(700,000)
Long-Term Debt	$ 499,400,000		499,300,000
5.60% Senior unsecured notes due 2044
Debt Instrument
Stated interest rate	5.60%
Outstanding Principal	$ 350,000,000		350,000,000
Premium (Discount)	(200,000)		(200,000)
Long-Term Debt	$ 349,800,000		349,800,000
5.05% Senior unsecured notes due 2045
Debt Instrument
Stated interest rate	5.05%
Outstanding Principal	$ 450,000,000		450,000,000
Premium (Discount)	(6,500,000)		(6,600,000)
Long-Term Debt	$ 443,500,000		443,400,000
5.45% Senior unsecured notes due 2047 | Senior unsecured notes
Debt Instrument
Stated interest rate	5.45%
Outstanding Principal	$ 500,000,000		0
Premium (Discount)	(100,000)		0
Long-Term Debt	$ 499,900,000		$ 0
5.45% Senior unsecured notes due 2047 | EnLink Midstream Partners, LP | Senior unsecured notes
Debt Instrument
Stated interest rate		5.45%
Outstanding Principal		$ 500,000,000

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Jun. 01, 2017USD ($)	May 11, 2017USD ($)	Sep. 30, 2017USD ($)subsidiary	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)extensionsubsidiaryshares	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Debt Instrument
Aggregate principal amount			$ 3,574,000,000		$ 3,574,000,000		$ 3,310,300,000
Gain on extinguishment of debt			$ 0	$ 0	$ 9,000,000	$ 0
EnLink Midstream Partners, LP
Debt Instrument
Repayment of outstanding borrowings		$ 495,200,000
Maximum | EnLink Midstream Partners, LP
Debt Instrument
Stated interest rate			5.60%		5.60%		7.10%
Minimum | EnLink Midstream Partners, LP
Debt Instrument
Stated interest rate			2.70%		2.70%		2.70%
ENLC credit facility due 2019
Debt Instrument
Maximum borrowing capacity			$ 250,000,000		$ 250,000,000
Units owned, limited partner interest (in shares) | shares					88,528,451
Membership interest in the General Partner					100.00%
Ownership interest					100.00%
Maximum consolidated leverage ratio			0.045		0.045
Outstanding borrowings			$ 74,000,000		$ 74,000,000		$ 27,800,000
Amount available for future borrowings			176,000,000		176,000,000
Aggregate principal amount			74,000,000		74,000,000		27,800,000
ENLC credit facility due 2019 | Letters of credit
Debt Instrument
Outstanding letters of credit			$ 0		$ 0
ENLC credit facility due 2019 | Maximum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA			0.04		0.04
ENLC credit facility due 2019 | Minimum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA			0.025		0.025
ENLC credit facility due 2019 | Letter of Credit
Debt Instrument
Maximum borrowing capacity			$ 125,000,000		$ 125,000,000
Number of wholly-owned subsidiaries that are used as the guarantee | subsidiary			2		2
ENLC credit facility due 2019 | LIBOR | Maximum
Debt Instrument
Variable rate					2.50%
ENLC credit facility due 2019 | LIBOR | Minimum
Debt Instrument
Variable rate					1.75%
ENLC credit facility due 2019 | Federal Funds
Debt Instrument
Variable rate					0.50%
ENLC credit facility due 2019 | Eurodollar
Debt Instrument
Variable rate					1.00%
ENLC credit facility due 2019 | Eurodollar | Maximum
Debt Instrument
Variable rate					1.50%
ENLC credit facility due 2019 | Eurodollar | Minimum
Debt Instrument
Variable rate					0.75%
ENLK credit facility due 2020 | EnLink Midstream Partners, LP
Debt Instrument
Maximum borrowing capacity			$ 1,500,000,000		$ 1,500,000,000
Ratio of consolidated indebtedness to consolidated EBITDA			0.05		0.05
Outstanding borrowings			$ 0		$ 0		120,000,000
Amount available for future borrowings			1,500,000,000		1,500,000,000
Additional amount available (not to exceed)					$ 500,000,000
Number of allowed extensions | extension					2
Extension period					1 year
Conditional acquisition purchase price (or more)					$ 50,000,000
Aggregate principal amount			0		0		120,000,000
ENLK credit facility due 2020 | EnLink Midstream Partners, LP | Letters of credit
Debt Instrument
Outstanding letters of credit			$ 9,200,000		$ 9,200,000
ENLK credit facility due 2020 | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA			0.055		0.055
ENLK credit facility due 2020 | LIBOR | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					1.75%
ENLK credit facility due 2020 | LIBOR | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					1.00%
ENLK credit facility due 2020 | Federal Funds | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					0.50%
ENLK credit facility due 2020 | Eurodollar | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					1.00%
ENLK credit facility due 2020 | Eurodollar | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					0.75%
ENLK credit facility due 2020 | Eurodollar | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate					0.00%
5.45% Senior unsecured notes due 2047 | Senior unsecured notes
Debt Instrument
Aggregate principal amount			$ 500,000,000		$ 500,000,000		$ 0
Stated interest rate			5.45%		5.45%
5.45% Senior unsecured notes due 2047 | EnLink Midstream Partners, LP | Senior unsecured notes
Debt Instrument
Aggregate principal amount		$ 500,000,000
Stated interest rate		5.45%
Percentage price of principal sold to the public		99.981%
5.45% Senior unsecured notes due 2047 | EnLink Midstream Partners, LP | Unsecured, 2022 Notes
Debt Instrument
Aggregate principal amount	$ 162,500,000
Stated interest rate	7.125%
Redemption price as a percentage of the principal amount	103.60%
Redemption price plus accrued interest	$ 174,100,000
Gain on extinguishment of debt					$ 9,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Total income tax expense	$ 3.1	$ 7.6	$ 9.3	$ 6
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Tax expense (benefit) at statutory federal rate (35%)	$ 3.3	$ 2	$ 6.8	$ (158)
Federal statutory tax rate	35.00%	35.00%	35.00%	35.00%
State income taxes expense (benefit), net of federal tax benefit	$ 0.2	$ 3.1	$ 0.5	$ (11.8)
Income tax expense from partnership	0.5	2.6	0.7	1.3
Unit-based compensation	0	0	2.3	0
Non-deductible expense related to asset impairment	0	(0.1)	0	173.8
Other	(0.9)	0	(1)	0.7
Total income tax expense	$ 3.1	$ 7.6	$ 9.3	$ 6

Certain Provisions of the Par54

Certain Provisions of the Partnership Agreement - Narrative and Distributions (Details) - USD ($)	1 Months Ended		3 Months Ended								9 Months Ended
	Sep. 30, 2017	Jan. 31, 2016	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016	Aug. 31, 2017	Nov. 30, 2014
Partnership agreement
Proceeds from sale of common units											$ 92,300,000	$ 110,600,000
EnLink Midstream Partners, LP
Partnership agreement
Percentage of available cash to distribute											100.00%
Period after quarter for distribution											45 days
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 1
Partnership agreement
Incentive distribution for general partner											13.00%
Incentive distribution, conditional distribution per unit (in dollars per share)											$ 0.25
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 2
Partnership agreement
Incentive distribution for general partner											23.00%
Incentive distribution, conditional distribution per unit (in dollars per share)											$ 0.3125
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 3
Partnership agreement
Incentive distribution for general partner											48.00%
Incentive distribution, conditional distribution per unit (in dollars per share)											$ 0.375
Common units | EnLink Midstream Partners, LP
Partnership agreement
Shelf registration for issuance of common units (up to)													$ 600,000,000
Distribution/unit (in dollars per share)			$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39
Common units | EnLink Midstream Partners, LP | 2014 EDA
Partnership agreement
Agreement for gross sales of common units (up to)														$ 350,000,000
Common units | EnLink Midstream Partners, LP | 2017 EDA
Partnership agreement
Common units sold											$ 5,300,000
Proceeds from sale of common units											92,300,000
Commissions											900,000
Registration Fees											200,000
Series B Preferred Unitholders
Partnership agreement
Proceeds from issuance of ENLK Series Preferred Units			$ 15,900,000	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0		0	724,100,000
Distribution paid-in kind (in shares)			410,681	1,178,672	1,154,147	1,130,131	1,106,616	1,083,589	992,445
Series C Preferred Unitholders
Partnership agreement
Proceeds from issuance of ENLK Series Preferred Units											393,700,000	$ 0
Limited Partner | Common units | EnLink Midstream Partners, LP | 2017 EDA
Partnership agreement
Amount of equity security remaining under equity distribution agreement	$ 580,100,000		$ 580,100,000								$ 580,100,000
Limited Partner | Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, units, sold in private placement		50,000,000
Shares issued, price per share (in dollars per share)		$ 15
Proceeds from issuance of ENLK Series Preferred Units		$ 724,100,000
Partners' capital, common units conversion ratio		1
Partners' capital account, conversion, consecutive trading days		30 days
Partners' capital account, conversion, duration prior to conversion		2 days
Partners' capital account, conversion, issuance price percentage, threshold		150.00%
Partners' capital account, conversion upon change of control, multiple		140.00%
Partners' capital account, dividend rate, percentage			7.50%	8.50%
Annual rate on issue price payable in kind		0.25%
Limited Partner | Series C Preferred Unitholders
Partnership agreement
Partners' capital account, redemption price	$ 1,000
Limited Partner | Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Proceeds from issuance of ENLK Series Preferred Units	$ 393,700,000
Partners' capital account, dividend rate, percentage	6.00%
Partners' capital account, units, sold in public offering	400,000
Partners' capital account, redemption price	$ 1,000
Partners' capital account, redemption period following review or appeal	120 days
Partners' capital account, redemption price following review or appeal	$ 1,020
LIBOR | Limited Partner | Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, distributions, variable floating rate percentage	4.11%

Certain Provisions of the Par55

Certain Provisions of the Partnership Agreement - Allocation of Income (Details) - General Partner - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Incentive distribution
Income allocation for incentive distributions	$ 14.8	$ 14.4	$ 44.1	$ 42.4
Unit-based compensation attributable to ENLC’s restricted units	(4.2)	(3.6)	(16.9)	(11.2)
General Partner share of net income (loss)	0	0	0.1	(2.4)
General Partner interest in net income	$ 10.6	$ 10.8	$ 27.3	$ 28.8

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	May 15, 2017	Nov. 14, 2016	Aug. 14, 2016	Aug. 12, 2016	May 13, 2016	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
EnLink Midstream, LLC interest in net income (loss)						$ 6.2				$ 0.7				$ 10.2	$ (456.1)
Distributed earnings allocated to:
Total distributed earnings						46.7				46.5				139.9	139
Undistributed loss allocated to:
Total undistributed loss						(40.5)				(45.8)				(129.7)	(595.1)
Net income (loss) allocated to:
Total net income (loss)						$ 6.2				$ 0.7				$ 10.2	$ (456.1)
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)						$ 0.03				$ 0				$ 0.06	$ (2.54)
Diluted (in dollars per share)						0.03				0				0.06	$ (2.54)
Distribution declared/unit (in dollars per share)						$ 0.255	$ 0.255	$ 0.255	$ 0.255	$ 0.255000000	$ 0.255	$ 0.255	$ 0.255	$ 0.255000000
Distribution paid/unit (in dollars per share)	$ 0.255000000	$ 0.255000000	$ 0.255	$ 0.255000000	$ 0.255000000
Unvested restricted units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
EnLink Midstream, LLC interest in net income (loss)						$ 0.1				$ (0.1)				$ 0.2	$ (5.2)
Distributed earnings allocated to:
Total distributed earnings						0.7				0.6				1.9	1.6
Undistributed loss allocated to:
Total undistributed loss						(0.6)				(0.7)				(1.7)	(6.8)
Net income (loss) allocated to:
Total net income (loss)						0.1				(0.1)				0.2	(5.2)
Common units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
EnLink Midstream, LLC interest in net income (loss)						6.1				0.8				10	(450.9)
Distributed earnings allocated to:
Total distributed earnings						46				45.9				138	137.4
Undistributed loss allocated to:
Total undistributed loss						(39.9)				(45.1)				(128)	(588.3)
Net income (loss) allocated to:
Total net income (loss)						$ 6.1				$ 0.8				$ 10	$ (450.9)

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic and diluted net income (loss) per unit:
Weighted average common units outstanding (in shares)	180.6	180	180.4	179.6
Diluted weighted average units outstanding:
Weighted average basic common units outstanding (in shares)	180.6	180	180.4	179.6
Dilutive effect of non-vested restricted incentive units (in shares)	1.2	1.1	1.3	0
Total weighted average diluted common units outstanding (in shares)	181.8	181.1	181.7	179.6

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Asset retirement obligation
Beginning balance	$ 13.5
Accretion expense	0.5
Ending balance	$ 14

Investment in Unconsolidated 59

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Equity method investments
Proceeds from sale of unconsolidated affiliate investment				$ 189.7	$ 0
Contributions		$ 1.5	$ 3.2	11.8	45
Distributions		4	37.4	11.4	52.3
Equity in income (loss)		4.4	1.1	5	(0.5)
Total investment in unconsolidated affiliates		$ 86.1		$ 86.1		$ 77.3
Gulf Coast Fractionators
Equity method investments
Ownership interest		38.75%		38.75%		38.75%
Contributions		$ 0	0	$ 0	0
Distributions		3.5	0.9	10.6	4.4
Equity in income (loss)		4.5	2.2	8.5	1.1
Howard Energy Partners
Equity method investments
Ownership interest						31.00%
Proceeds from sale of unconsolidated affiliate investment	$ 189.7
Contributions		0	3.2	0	45
Distributions		0	36.5	0	47.9
Equity in income (loss)		$ 0	(1.1)	$ (3.4)	(1.6)
Cedar Cove JV
Equity method investments
Ownership interest		30.00%		30.00%		30.00%
Contributions		$ 1.5	0	$ 11.8	0
Distributions		0.5	0	0.8	0
Equity in income (loss)		(0.1)	0	(0.1)	0
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates		86.1		86.1		$ 270.4
EnLink Midstream Partners, LP | Gulf Coast Fractionators
Equity method investments
Total investment in unconsolidated affiliates		46.4		46.4		48.5
EnLink Midstream Partners, LP | Howard Energy Partners
Equity method investments
Total investment in unconsolidated affiliates		0		0		193.1
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates		$ 39.7		$ 39.7		$ 28.8
Preferred Units | Howard Energy Partners
Equity method investments
Contributions			3.2		32.7
Distributions			$ 32.7		$ 32.7

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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Allocation
Compensation expense	$ 10.2	$ 7.4	$ 38.9	$ 22.5
Amount of related income tax benefit recognized in net income (1)	2.4	1.7	9.1	5.4
Tax expense excluded from income tax benefit	0	0	2.3	0
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	7.4	5.8	28.5	17.7
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	2.8	1.6	10.4	4.8
Non-controlling interest in unit-based compensation
Allocation
Compensation expense	$ 3.9	$ 2.7	$ 14.6	$ 8.3

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Restricted incentive units
Number of Units
Non-vested, beginning of period (in shares)				1,897,298
Granted (in shares)				817,201
Vested (in shares)	(258,606)			(775,973)
Forfeited (in shares)				(31,636)
Non-vested, end of period (in shares)		1,906,890		1,906,890
Aggregate intrinsic value, end of period		$ 32.9		$ 32.9
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 19.96
Granted (in dollars per share)				19.24
Vested (in dollars per share)				28.28
Forfeited (in dollars per share)				16.53
Non-vested, end of period (in dollars per share)		$ 16.32		$ 16.32
Fair value of units vested	$ 5	$ 1.1	$ 0.6	$ 21.9	$ 12.4
Units withheld for payroll taxes (in shares)				238,312
Aggregate intrinsic value of units vested		0.6	0.3	$ 15.2	4.1
Unrecognized compensation cost related to non-vested restricted incentive units		$ 14.2		$ 14.2
Unrecognized compensation costs, weighted average period for recognition				1 year 10 months
Vesting period				3 years
Performance units
Number of Units
Non-vested, beginning of period (in shares)				384,264
Granted (in shares)				164,575
Forfeited (in shares)				0
Non-vested, end of period (in shares)		548,839		548,839
Aggregate intrinsic value, end of period		$ 9.5		$ 9.5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 19.30
Granted (in dollars per share)				28.77
Forfeited (in dollars per share)				0
Non-vested, end of period (in dollars per share)		$ 22.14		$ 22.14
Unrecognized compensation cost related to non-vested restricted incentive units		$ 6		$ 6
Unrecognized compensation costs, weighted average period for recognition				2 years
Vesting period				3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price (in dollars per share)	$ 18.29
Risk-free interest rate	1.62%
Volatility factor	52.07%
Distribution yield	5.40%
Performance units | Minimum
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				200.00%
EnLink Midstream Partners, LP | Restricted incentive units
Number of Units
Non-vested, beginning of period (in shares)				2,024,820
Granted (in shares)				859,595
Vested (in shares)	(262,288)			(851,753)
Forfeited (in shares)				(32,225)
Non-vested, end of period (in shares)		2,000,437		2,000,437
Aggregate intrinsic value, end of period		$ 33.5		$ 33.5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 19.05
Granted (in dollars per share)				18.41
Vested (in dollars per share)				25.90
Forfeited (in dollars per share)				16.28
Non-vested, end of period (in dollars per share)		$ 15.91		$ 15.91
Fair value of units vested	$ 5.1	$ 1.1	0.5	$ 22.1	9.5
Units withheld for payroll taxes (in shares)				273,848
Aggregate intrinsic value of units vested		0.6	$ 0.3	$ 16.3	$ 4.1
Unrecognized compensation cost related to non-vested restricted incentive units		$ 14.6		$ 14.6
Unrecognized compensation costs, weighted average period for recognition				1 year 8 months
Vesting period				3 years
EnLink Midstream Partners, LP | Performance units
Number of Units
Non-vested, beginning of period (in shares)				408,637
Granted (in shares)				176,648
Forfeited (in shares)				0
Non-vested, end of period (in shares)		585,285		585,285
Aggregate intrinsic value, end of period		$ 9.8		$ 9.8
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)				$ 18.27
Granted (in dollars per share)				25.73
Forfeited (in dollars per share)				0
Non-vested, end of period (in dollars per share)		$ 20.52		$ 20.52
Unrecognized compensation cost related to non-vested restricted incentive units		$ 5.9		$ 5.9
Unrecognized compensation costs, weighted average period for recognition				1 year 11 months
Vesting period				3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price (in dollars per share)	$ 17.55
Risk-free interest rate	1.62%
Volatility factor	43.94%
Distribution yield	8.70%
EnLink Midstream Partners, LP | Performance units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting				0.00%
EnLink Midstream Partners, LP | Performance units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting				200.00%

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	May 31, 2017	Dec. 31, 2016
Derivatives
Accumulated other comprehensive loss	$ (2)	$ (2)	$ (2.2)	$ 0
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	(0.1)	(0.1)
Realized gain (loss) on derivatives	$ 0.4	$ 0.4
4.85% Senior unsecured notes due 2026 | EnLink Midstream Partners, LP
Derivatives
Stated interest rate	4.85%	4.85%

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivatives
Realized gain (loss) on derivatives	$ 0.4		$ 0.4
Loss on derivative activity	(5.5)	$ (0.5)	(1.1)	$ (6.6)
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
Change in fair value of derivatives	(3.3)	(1.6)	3.8	(16)
Realized gain (loss) on derivatives	(2.2)	1.1	(4.9)	9.4
Loss on derivative activity	$ (5.5)	$ (0.5)	$ (1.1)	$ (6.6)

Derivatives - Fair Value of Ass

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivatives
Fair value of derivative assets — current	$ 4.6	$ 1.3
Fair value of derivative assets — long-term	0.1	0
Fair value of derivative liabilities — current	(7.2)	(7.6)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets — current	4.6	1.3
Fair value of derivative assets — long-term	0.1	0
Fair value of derivative liabilities — current	(7.2)	(7.6)
Net fair value of derivatives	$ (2.5)	$ (6.3)

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)MMBTUgalMMBbls	Dec. 31, 2016USD ($)
Derivatives
Fair Value	$ (2.5)	$ (6.3)
Commodity
Derivatives
Fair Value	(2.5)
Maximum loss if counterparties fail to perform	4.7
Possible reduction in maximum loss if counterparties fail to perform	$ 1.7
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	35.8
Fair Value	$ (4.9)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	25.1
Fair Value	$ 1.9
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	20.5
Fair Value	$ 1.3
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	23.2
Fair Value	$ (0.7)
Commodity | Condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	0.1
Fair Value	$ (0.1)

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - Level 2 - Recurring - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair Value
Fair Value	$ (2.5)	$ (6.3)
Commodity Swaps
Fair Value
Fair Value	$ (2.5)	$ (6.3)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Fair Value
Debt issuance costs	$ 27,200,000	$ 24,600,000
ENLC credit facility due 2019
Fair Value
Outstanding borrowings	74,000,000	27,800,000
EnLink Midstream Partners, LP
Fair Value
Senior unsecured debt	$ 3,500,000,000	$ 3,100,000,000
EnLink Midstream Partners, LP | Minimum
Fair Value
Stated interest rate	2.70%	2.70%
EnLink Midstream Partners, LP | Maximum
Fair Value
Stated interest rate	5.60%	7.10%
EnLink Midstream Partners, LP | ENLK credit facility due 2020
Fair Value
Outstanding borrowings	$ 0	$ 120,000,000
EnLink Midstream Partners, LP | Carrying Value
Fair Value
Long-term debt	3,540,500,000	3,295,300,000
Installment Payables	243,000,000	473,200,000
Obligations under capital lease	4,400,000	6,600,000
EnLink Midstream Partners, LP | Fair Value
Fair Value
Long-term debt	3,638,700,000	3,253,600,000
Installment Payables	243,700,000	476,600,000
Obligations under capital lease	$ 3,700,000	$ 6,100,000

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	1 Months Ended				3 Months Ended	9 Months Ended
	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Aug. 31, 2014USD ($)	Jul. 31, 2013defendant	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)
Commitments and Contingencies
Litigation settlement amount awarded from other party	$ 8.5	$ 17.5	$ 6.1			$ 26
LDEQ
Commitments and Contingencies
Litigation settlement amount awarded to other party					$ 0.3
Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans | Judicial ruling
Commitments and Contingencies
Number of energy companies sued (in defendant) | defendant				100

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting
Product sales		$ 1,056.7	$ 771	$ 2,973.9	$ 2,097.8
Product sales—related parties		35.3	43.1	107.3	99.3
Midstream services		136.4	125.7	395.7	348.5
Midstream services—related parties		175	165.3	507.6	488.5
Cost of sales	[1]	(1,053.2)	(788.2)	(2,987.9)	(2,106.8)
Operating expenses		(102.1)	(98)	(308.8)	(296.3)
Loss on derivative activity		(5.5)	(0.5)	(1.1)	(6.6)
Segment profit (loss)		242.6	218.4	686.7	624.4
Depreciation and amortization		(136.3)	(126.2)	(407.1)	(373)
Impairments		(1.8)	0	(8.8)	(873.3)
Goodwill		1,542.2	1,542.2	1,542.2	1,542.2	$ 1,542.2
Capital expenditures		169.7	146.9	636.3	407.5
Total identifiable assets		10,548.3		10,548.3		10,275.9
Corporate
Segment Reporting
Product sales		0	0	0	0
Product sales—related parties		(199.9)	(99.2)	(493.1)	(209.8)
Midstream services		0	0	0	0
Midstream services—related parties		(35.4)	(27)	(96.8)	(60.1)
Cost of sales		235.3	126.2	589.9	269.9
Operating expenses		0	0	0	0
Loss on derivative activity		(5.5)	(0.5)	(1.1)	(6.6)
Segment profit (loss)		(5.5)	(0.5)	(1.1)	(6.6)
Depreciation and amortization		(2.6)	(2.4)	(7.3)	(6.8)
Impairments		0		0	(307)
Goodwill		1,119.9	1,119.9	1,119.9	1,119.9
Capital expenditures		2.1	8.6	25.6	15.4
Total identifiable assets		1,377.9		1,377.9		1,422.7
Texas | Operating Segments
Segment Reporting
Product sales		80.8	61.3	240.5	165.7
Product sales—related parties		130.6	81.9	352.6	191.9
Midstream services		29.1	27.5	85.1	78.1
Midstream services—related parties		106.7	109.5	319	331.7
Cost of sales		(198.5)	(134.1)	(554.7)	(329)
Operating expenses		(41.1)	(42.9)	(127.9)	(125.2)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		107.6	103.2	314.6	313.2
Depreciation and amortization		(52.5)	(48.7)	(161.9)	(143.6)
Impairments		0		0	(473.1)
Goodwill		232	232	232	232
Capital expenditures		39.1	51.8	107.1	132.3
Total identifiable assets		3,113		3,113		3,142.6
Louisiana | Operating Segments
Segment Reporting
Product sales		642.3	430.9	1,735.5	1,118.1
Product sales—related parties		10	24.4	25.6	47
Midstream services		50.3	57.2	159.7	165.1
Midstream services—related parties		35.9	29.9	100.2	68.1
Cost of sales		(662.7)	(471.5)	(1,803.1)	(1,199.1)
Operating expenses		(24.8)	(23.5)	(74.8)	(72.2)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		51	47.4	143.1	127
Depreciation and amortization		(29.3)	(28.8)	(86.8)	(86.7)
Impairments		0		0	0
Goodwill		0	0	0	0
Capital expenditures		7.5	15.4	55.8	52.2
Total identifiable assets		2,395.5		2,395.5		2,349.3
Oklahoma | Operating Segments
Segment Reporting
Product sales		42.5	16.2	84.7	32.9
Product sales—related parties		94.6	36	221.4	69.1
Midstream services		44.3	24.2	105.2	57.3
Midstream services—related parties		63	47.7	171.8	134.4
Cost of sales		(148.2)	(58.3)	(335.9)	(109.2)
Operating expenses		(17.1)	(12.6)	(45.9)	(37.2)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		79.1	53.2	201.3	147.3
Depreciation and amortization		(40.2)	(35.6)	(115.3)	(104.2)
Impairments		0		0	0
Goodwill		190.3	190.3	190.3	190.3
Capital expenditures		107.7	58.3	383.4	190.6
Total identifiable assets		2,814.7		2,814.7		2,524.5
Crude and Condensate | Operating Segments
Segment Reporting
Product sales		291.1	262.6	913.2	781.1
Product sales—related parties		0	0	0.8	1.1
Midstream services		12.7	16.8	45.7	48
Midstream services—related parties		4.8	5.2	13.4	14.4
Cost of sales		(279.1)	(250.5)	(884.1)	(739.4)
Operating expenses		(19.1)	(19)	(60.2)	(61.7)
Loss on derivative activity		0	0	0	0
Segment profit (loss)		10.4	15.1	28.8	43.5
Depreciation and amortization		(11.7)	(10.7)	(35.8)	(31.7)
Impairments		(1.8)		(8.8)	(93.2)
Goodwill		0	0	0	0
Capital expenditures		13.3	$ 12.8	64.4	$ 17
Total identifiable assets		$ 847.2		$ 847.2		$ 836.8
[1]	Includes related party cost of sales of $47.3 million and $33.7 million for the three months ended September 30, 2017 and 2016, respectively, and $126.9 million and $126.0 million for the nine months ended September 30, 2017 and 2016, respectively.

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting [Abstract]
Segment profits	$ 242.6	$ 218.4	$ 686.7	$ 624.4
General and administrative expenses	(31.3)	(29.3)	(98.5)	(94.7)
Gain (loss) on disposition of assets	(1.1)	3	(0.8)	2.9
Depreciation and amortization	(136.3)	(126.2)	(407.1)	(373)
Impairments	(1.8)	0	(8.8)	(873.3)
Gain on litigation settlement	0	0	26	0
Operating income (loss)	$ 72.1	$ 65.9	$ 197.5	$ (713.7)

Supplemental Cash Flow Inform71

Supplemental Cash Flow Information (Details) - EnLink Oklahoma T.O. - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
EnLink Midstream Partners, LP
Noncash Transactions [Line Items]
Installment payable, net of discount of $79.1 million	$ 0	$ 420.9
Installment payable discount		79.1
Common Units
Noncash Transactions [Line Items]
Non-cash issuance of ENLC common units	$ 0	$ 214.9

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Natural gas and NGLs inventory	$ 59.1	$ 17.4
Prepaid expenses and other	14.3	16.1
Natural gas and NGLs inventory, prepaid expenses and other	73.4	33.5
Accrued interest	64.8	34.2
Accrued wages and benefits, including taxes	23.2	19
Accrued ad valorem taxes	33.5	23.5
Capital expenditure accruals	43.6	64.6
Onerous performance obligations	15.4	15.9
Other	54.7	60.3
Other current liabilities	$ 235.2	$ 217.5