EnLink Midstream (ENLC) 10-K 17 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ / shares in Units, $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 10, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Amendment Flag	false
Entity Registrant Name	Enlink Midstream, LLC
Entity Central Index Key	1,592,000
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		179,901,914
Entity Public Float			$ 1.5
Common unit price			$ 31.09

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 18	$ 68.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.3	37.5	139
Accrued revenues and other	268.8	253.3
Related party	110.8	121.6
Fair value of derivative assets	16.8	16.7
Natural gas and natural gas liquids inventory, prepaid expenses and other	41.8	48.8
Total current assets	493.7	647.8
Property and equipment, net of accumulated depreciation of $1,757.6 and $1,426.3, respectively	5,666.8	5,042.8
Intangible assets, net of accumulated amortization of $54.6 and $36.5, respectively	689.9	533
Goodwill	2,413.9	3,684.7
Fair value of derivative assets	0	10
Investments in unconsolidated affiliate investments	274.3	270.8
Other assets, net	26.5	17.6
Total assets	9,565.1	10,206.7
Current Liabilities:
Drafts payable	0.5	13.2
Accounts payable	32.7	108.6
Accounts payable to related party	14.8	3
Accrued gas, condensate and crude oil purchases	206.7	204.5
Fair value of derivative liabilities	2.9	3
Other current liabilities	174.8	152.3
Total current liabilities	432.4	484.6
Long-term debt	3,089.8	2,022.5
Asset retirement obligations	12.9	12.4
Other long-term liabilities	65.9	83.8
Deferred tax liability	532.1	526.6
Fair value of derivative liabilities	0.1	2
Redeemable non-controlling interest	7	0
Members' equity:
Members' equity (164,242,160 and 164,055,004 units issued and outstanding at December 31, 2015 and 2014, respectively)	2,285.7	2,774.3
Non-controlling interest	3,139.2	4,196.8
Net Devon investment	0	103.7
Total members' equity	$ 5,424.9	$ 7,074.8
Commitments and contingencies (Note 15)
Total liabilities and members' equity	$ 9,565.1	$ 10,206.7

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets:
Allowance for bad debt	$ 0.3	$ 0
Property and equipment, accumulated depreciation	1,757.6	1,426.3
Intangible assets, accumulated amortization	$ 54.6	$ 36.5
Members' equity:
Common unitholders	164,242,160	164,055,004

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Product sales		$ 3,253.7	$ 2,159.3	$ 179.4
Product sales- affiliates		119.4	505.6	2,116.5
Midstream services		451	253.4	0
Midstream services- affiliates		618.6	567.4	0
Gain on derivatives activity		9.4	22.1	0
Total revenues		4,452.1	3,507.8	2,295.9
Operating costs and expenses:
Cost of sales	[1]	3,245.3	2,494.5	1,736.3
Operating expenses	[2]	419.9	283.6	156.2
General and administrative	[3]	136.9	97.3	45.1
Depreciation and amortization		387.3	284.3	187
Gain (loss) on disposition of property		1.2	(0.1)	0
Impairments		1,563.4	0	0
Gain on litigation settlement		0	(6.1)	0
Total operating costs and expenses		5,754	3,153.5	2,124.6
Operating income (loss)		(1,301.9)	354.3	171.3
Other income (expense):
Interest expense, net of interest income		(103.3)	(49.8)	0
Income from unconsolidated affiliates		20.4	18.9	14.8
Gain on extinguishment of debt		0	3.2	0
Other income (expense)		0.8	(0.5)	0
Total other income (expense)		(82.1)	(28.2)	14.8
Income (loss) from continuing operations before non-controlling interest and income taxes		(1,384)	326.1	186.1
Income tax provision		(25.7)	(76.4)	(67)
Net income (loss) from continuing operations		(1,409.7)	249.7	119.1
Income (loss) from discontinued operations, net of tax		0	1	(2.3)
Income from discontinued operations attributable to non-controlling interest, net of tax		0	0	(1.3)
Discontinued operations, net of tax		0	1	(3.6)
Net income (loss)		(1,409.7)	250.7	115.5
Net income (loss) attributable to the non-controlling interest		(1,054.5)	126.7	0
Net income (loss) attributable to Enlink Midstream, LLC		(355.2)	124	115.5
Predecessor interest in net income	[4]	0	35.5	0
Devon investment interest in net income (loss)		1.8	(2)	0
Enlink Midstream, LLC interest in net income (loss)		$ (357)	$ 90.5	$ 0
Earnings Per Share, Diluted		$ (2.17)	$ 0.55	$ 0
Net income attributable to Enlink Midstream Partners, LP per limited partners' unit:
Basic common unit (usd per unit)		$ (2.17)	$ 0.55	$ 0
[1]	Includes $141.3 million, $354.3 million and $1,588.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate purchased gas.
[2]	Includes $0.5 million, $5.9 million and $36.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate operating expenses from Devon.
[3]	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.
[4]	Represents net income attributable to the Predecessor for the periods prior to March 7, 2014.

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Affiliate purchased gas	[1]	$ 3,245.3	$ 2,494.5	$ 1,736.3
Affiliate general and administrative expenses	[2]	(136.9)	(97.3)	(45.1)
Affiliated Entity
Affiliate purchased gas		141.3	354.3	1,588.2
Affiliate operating expenses		0.5	5.9	36.2
Affiliate general and administrative expenses		$ (0.2)	$ (11.6)	$ (45.1)
[1]	Includes $141.3 million, $354.3 million and $1,588.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate purchased gas.
[2]	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.

Consolidated Statements of Chan

Consolidated Statements of Changes in Members' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Units	Devon Energy Corporation	Non- Controlling Interest
Non-controlling interest				$ 48.7
Increase (Decrease) in Partners' Capital
Members' equity (164,242,160 and 164,055,004 units issued and outstanding at December 31, 2015 and 2014, respectively)		$ 0
Balance at the beginning of the period (Predecessor Equity) at Dec. 31, 2012	$ 1,953.3
Balance at the beginning of the period at Dec. 31, 2012	2,002
Balance at the beginning of the period (Units) at Dec. 31, 2012		0
Increase (Decrease) in Partners' Capital
Distributions to the Predecessor | Predecessor Equity	(285.1)
Distributions to the Predecessor	(285.1)
Distributions to non-controlling interest	(1.6)			(1.6)
Sale of non-controlling interest	(47.1)			(47.1)
Unit-based compensation	0
Net income (loss) | Predecessor Equity	115.5
Net income (loss)	115.5
Balance at the end of the period (Predecessor Equity) at Dec. 31, 2013	1,783.7
Balance at the end of the period at Dec. 31, 2013	1,783.7
Balance at the end of the period (Units) at Dec. 31, 2013		0
Members' Equity Attributable To Devon Investment			$ 0
Non-controlling interest				0
Increase (Decrease) in Partners' Capital
Members' equity (164,242,160 and 164,055,004 units issued and outstanding at December 31, 2015 and 2014, respectively)		$ 0
Distributions to the Predecessor | Predecessor Equity	(71.9)
Distributions to the Predecessor	(71.9)
Distributions to non-controlling interest	(204.3)			(204.3)
Issuance of units for reorganization of predecessor equity | Predecessor Equity	(1,747.3)
Issuance of units for reorganization of predecessor equity		$ 941.7		805.6
Issuance of units for reorganization of predecessor equity (units)		115.5
Issuance of common units for acquisition of Company	4,670.3	$ 1,822.6		2,847.7
Issuance of common units for acquisition of Company (Units)		48.5
Elimination of deferred taxes attributable to non-controlling interest in predecessor equity	204.9			204.9
Issuance of units by the Partnership	412			412
Change in equity due to issuance of units by the partnership	0.7	$ (1.1)		1.8
Conversion of restricted units for common units, net of units withheld for taxes	(1.1)	(1.2)		0.1
Non-controlling partner's impact on conversion of restricted units and options	(0.3)			(0.3)
Unit-based compensation	(19.6)	$ (10.6)		(9)
Conversion of restricted units for common units, net of units withheld for taxes (Units)		0.1
Distributions to members	(89)	$ (89)
Purchase of non-controlling interest	(12.5)			(12.7)
Non-controlling interest contributions	6.3	0.2		6.3
Contribution By Affiliate			105.7
Net income (loss) | Predecessor Equity	35.5
Net income (loss)	250.7	$ 90.5	(2)	126.7
Balance at the end of the period (Predecessor Equity) at Dec. 31, 2014	0
Balance at the end of the period at Dec. 31, 2014	7,074.8
Balance at the end of the period (Units) at Dec. 31, 2014		164.1
Members' Equity Attributable To Devon Investment	103.7		103.7
Non-controlling interest	4,196.8			4,196.8
Redeemable Noncontrolling Interest	0
Increase (Decrease) in Partners' Capital
Members' equity (164,242,160 and 164,055,004 units issued and outstanding at December 31, 2015 and 2014, respectively)	(2,774.3)	$ (2,774.3)
Distributions to non-controlling interest	(359.5)			(359.5)
Issuance of units by the Partnership	384.4			384.4
Change in equity due to issuance of units by the partnership	(5.2)	8.5		(13.7)
Non-controlling partner's impact of conversion of restricted units	(2.5)			(2.5)
Conversion of restricted units for common units, net of units withheld for taxes	(2.9)	(2.9)
Unit-based compensation	(36.1)	$ (18.5)		(17.6)
Conversion of restricted units for common units, net of units withheld for taxes (Units)		0.1
Distributions to members	(162.8)	$ (162.8)
Non-controlling interest contributions	16.4			16.4
Adjustment related to mandatory redemption of E2 non- controlling interest	(5.4)			(5.4)
Contribution from Devon to the Company	7.1	7.1
Redeemable non-controlling interest	(7)			(7)
Contribution By Affiliate	27.8		25.6	2.2
Distribution To Affiliate	(166.7)		(131.1)	(35.6)
Net income (loss)	(1,409.7)	$ (357)	1.8	(1,054.5)
Balance at the end of the period (Predecessor Equity) at Dec. 31, 2015	0
Balance at the end of the period at Dec. 31, 2015	5,424.9
Balance at the end of the period (Units) at Dec. 31, 2015		164.2
Increase (Decrease) in Partners' Capital
Redeemable Noncontrolling Interest Reclassifications Between Permanen And Temporary Equity	7
Members' Equity Attributable To Devon Investment	0		$ 0
Non-controlling interest	3,139.2			$ 3,139.2
Redeemable Noncontrolling Interest	7
Members' equity (164,242,160 and 164,055,004 units issued and outstanding at December 31, 2015 and 2014, respectively)	$ (2,285.7)	$ (2,285.7)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss) from continuing operations	$ (1,409.7)	$ 249.7	$ 119.1
Adjustments to reconcile net income (loss) to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Depreciation and amortization	387.3	284.3	187
Asset impairments	1,563.4	0	0
Accretion expense	0.6	0.5	0.5
Gain on extinguishment of debt	0	(3.2)	0
(Gain) loss on disposition of property	1.2	(0.1)	0
Non-cash unit-based compensation	36.1	19.6	0
Deferred tax expense	22.6	67.4	35.5
Gain on derivatives recognized in net income	(9.4)	(22.1)	0
Cash settlements on derivatives	17.1	(0.3)	0
Amortization of debt issue costs	3.3	1.9	0
Amortization of premium on notes	(2.9)	(2.9)	0
Redeemable non-controlling interest expense	(1.8)	0	0
Distribution of earnings from unconsolidated affiliates	21.6	7	10.9
Income from unconsolidated affiliates	(20.4)	(18.9)	(14.8)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	197.5	(98.9)	0
Natural gas and natural gas liquids, prepaid expenses and other	(6.7)	(8.2)	0.7
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(171.4)	(16.9)	(8.6)
Net cash provided by operating activities	628.4	458.9	330.3
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(572.3)	(796)	(244.3)
Acquisition of business, net of cash acquired	(524.2)	(357.9)	0
Proceeds from insurance settlement	2.9	0	0
Proceeds from sale of property	1	0.1	0
Investment in unconsolidated affiliates	(25.8)	(5.7)	0
Distribution from unconsolidated affiliates in excess of earnings	21.1	10.9	1.1
Net cash used in investing activities	(1,097.3)	(1,148.6)	(243.2)
Cash flows from financing activities:
Proceeds from borrowings	3,204.4	3,367.8	0
Payments on borrowings	(2,134.3)	(2,792.7)	0
Payments on capital lease obligations	(3.6)	(3)	0
Increase (decrease) in drafts payable	(12.7)	10.2	0
Debt refinancing costs	(9.6)	(19.7)	0
Conversion of restricted units, net of units withheld for taxes	(2.9)	(1.1)	0
Conversion of Partnership's restricted units, net of units withheld for taxes	(2.5)	(0.7)	0
Proceeds from issuance of Partnership common units	24.4	412	0
Distributions to non-controlling interest	(359.5)	(204.3)	0
Contributions by non-controlling interest	16.4	6.3	0
Distribution to members	162.8	89	0
Distributions to Predecessor	0	(21.3)	(151.2)
Contribution from Devon	27.8	105.7	0
Proceeds from exercise of Partnership unit options	0.1	0.4	0
Purchase of non-controlling interest	0	(12.5)	0
Distribution to Devon for VEX interests transferred (Note 3)	166.7	0	0
Net cash provided by (used in) financing activities	418.5	758.1	(151.2)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Net cash provided by operating activities	0	5	31.1
Net cash provided by (used in) investing activities	0	(0.6)	154.2
Net cash used in financing activities-net distributions to Devon and non-controlling interests	0	(4.4)	(136.8)
Net cash provided by discontinued operations	0	0	48.5
Net increase (decrease) in cash and cash equivalents	(50.4)	68.4	(15.6)
Cash and cash equivalents, beginning of year	68.4	0	15.6
Cash and cash equivalents, end of year	18	68.4	0
Cash paid for interest	110	55.8	0
Cash paid for income taxes	$ 13.7	$ 7.5	$ 0

Organization and Summary of Sig

Organization and Summary of Significant Agreement	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Agreements	Organization and Summary of Significant Agreements (a) Organization of Business and Nature of Business EnLink Midstream, LLC (“ENLC”) is a Delaware limited liability company formed in October 2013. Effective as of March 7, 2014 , EnLink Midstream, Inc. (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “mergers”). Pursuant to the mergers, each of EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 6.1% limited partner interest in EnLink Midstream LP ( the “Partnership”) as of December 31, 2015 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 units to a wholly-owned subsidiary of Devon, which represented approximately 70% of the outstanding limited liability company interests in ENLC. Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the “February Transferred Interests”) to the Partnership in a drop down transaction (the “February EMH Drop Down”) in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.5% limited partner interest in the Partnership as of December 31, 2015. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the “May Transferred Interests”) to the Partnership in a drop down transaction (the “May EMH Drop Down” and together with the February EMH Drop Down, the “EMH Drop Downs”) in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.0% limited partner interest in the Partnership as of December 31, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. Our assets consist of equity interests in the Partnership. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. As of December 31, 2015 , our interests in the Partnership consist of the following: • 88,528,451 common units representing an aggregate 26.5% limited partner interest in the Partnership; and • 100.0% ownership interest in EnLink Midstream Partners GP, LLC , the general partner of the Partnership, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership. (b) Nature of Business The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. The Partnership connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Partnership operates processing plants that processes gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Partnership provides a variety of crude oil and condensate services, which includes crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership also has crude oil and condensate terminal facilities that provides access for crude oil and condensate producers to premium markets. The Partnership's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to its fractionators in south Louisiana. The Partnership's crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. The Partnership's processing plants remove NGLs and CO 2 from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies	Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Further, the consolidated financial statements give effect to the business combination and related transactions discussed above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of ENLC after the business combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC's non-controlling interests in the Partnership, were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired was recorded as goodwill. Financial results on and subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and EMI, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. All significant intercompany transactions and balances have been eliminated. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non-contributed assets have been presented as discontinued operations. In conjunction with the business combination, Midstream Holdings became a non-taxable entity which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity. On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to “Devon investment interest in net income” on the Company's Consolidated Statements of Operations. (b) Management's Use of Estimates The preparation of financial statements in accordance with US GAAP requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. (c) Revenue Recognition The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization and brine services, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the Consolidated Statements of Operations as follows: • Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above. • Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above. The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). (d) Gas Imbalance Accounting Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Company had imbalance payables of $2.6 million and $1.5 million at December 31, 2015 and 2014 , respectively, which approximate the fair value of these imbalances. The Company had imbalance receivables of $3.6 million and $1.2 million at December 31, 2015 and 2014 , respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued Revenue and other” and “Accrued gas, condensate and crude oil purchases”, respectively, on the Consolidated Balance Sheets. (e) Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. (f) Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory The Partnership's inventories of products consist of natural gas, NGLs, crude oil and condensate. The Partnership reports these assets at the lower of cost or market value which is determined by using the first-in, first-out method. (g) Property, Plant, and Equipment Property, plant and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value, including the Partnership's assets acquired by the Predecessor in the business combination. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Subsequent to the business combination, interest costs for material projects are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use. The components of property, plant and equipment are as follows (in millions): Year Ended December 31, 2015 2014 Transmission assets $ 1,285.1 $ 1,100.1 Gathering systems 2,999.2 2,391.9 Gas processing plants 2,673.7 2,356.1 Other property and equipment 135.9 379.5 Construction in process 330.5 241.5 Property, plant and equipment 7,424.4 6,469.1 Accumulated depreciation (1,757.6 ) (1,426.3 ) Property, plant and equipment, net $ 5,666.8 $ 5,042.8 Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, the Company is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Company changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Company’s legacy assets. In accordance with FASB ASC 250, the Company determined that the change in depreciation method was a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method was applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense for the year ended December 31, 2014 by approximately $29.4 million and $0.18 per unit. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years Depreciation expense of $331.3 million , $247.8 million and $187.0 million was recorded for the years ended December 31, 2015 , 2014 and 2013 , respectively. Gain or Loss on Disposition. Upon the disposition or retirement of property, plant and equipment related to continuing operations, any gain or loss is recognized in operating income in the statement of operations. When a disposition or retirement occurs which qualifies as discontinued operations, any gain or loss is recognized as income or loss from discontinued operations in the statement of operations. We recognized a loss on disposition of assets of $1.2 million for the year ended December 31, 2015 , which primarily relates to the retirement of a compressor due to fire damage. For the year ended December 31, 2015 , we retired net property, plant and equipment of $5.1 million , which was offset by $2.9 million of nonrefundable cash proceeds collected from our insurance carrier and $1.0 million of proceeds from the sale of property. Additionally, we collected $2.4 million of business interruption proceeds from our insurance carrier which was presented in the Midstream services revenue line item in the Consolidated Statement of Operations as of December 31, 2015 . Impairment Review. We evaluate our property, plant 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. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. Our estimate of cash flows is based on assumptions which include (1) the amount of fee based services, the purchase and resale margins and the volume of natural gas, NGL, condensate and crude oil available to the asset, (2) markets available to the asset, (3) operating expenses, and (4) future natural gas, crude oil, condensate and NGL product prices. The volume of available natural gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. During December 2015, the Partnership recognized a $12.1 million impairment on property, plant and equipment, primarily related to costs associated with the cancellation of various capital projects in its Texas, Louisiana and Crude and Condensate segments. (h) Equity Method of Accounting The Company accounts for investments where it does not control the investment but has the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by the Company’s proportionate share of the investee’s net income and by contributions made, and decreased by the Predecessor’s proportionate share of the investee’s net losses and by distributions received. The Company evaluates its unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. (i) Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company evaluates goodwill for impairment annually as of October 31 st , 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. The Company first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. Company may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During the third and fourth quarters of 2015, the Company determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in its unit price caused a change in circumstances warranting an interim impairment test. Based on these triggering events, the Company performed a goodwill impairment analysis on all reporting units. Through the analysis, a goodwill impairment loss for the Company's Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015, which is included in impairment expense in the Consolidated Statements of Operations. See Note 4- Goodwill and Intangible Assets for further discussion regarding the goodwill impairment. (j) 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. (k) Asset Retirement Obligations The Company recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Company’s retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight line depreciation method similar to that used for the associated property, plant and equipment. (l) Other Long-Term Liabilities Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the business combination of $62.8 million and $80.7 million for the years ended December 31, 2015 and 2014 , respectively. The Company has one delivery contract which requires it to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Company realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchase gas costs. (m) Derivatives The Company uses derivative instruments to hedge against changes in cash flows related to product price only. We generally determine the fair value of swap contracts based on the difference between the derivative's fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities in accordance with FASB ASC 815. Changes in fair value of derivative instruments are recorded in gain (loss) on derivative activity in the period of change. Realized gains and losses on commodity related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statement of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities. (n) Concentrations of Credit Risk Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than the Company's exposure to Devon discussed below, since the Company's customers represent a broad and diverse group of energy marketers and end users. In addition, the Company continually monitors and reviews credit exposure of its marketing counter-parties and letters of credit or other appropriate security are obtained when considered necessary to limit the risk of loss. The Company records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Company had a reserve for uncollectible receivables as of December 31, 2015 of $0.3 million and had no reserve for uncollectible receivables as of December 31, 2014 . During the year ended December 31, 2015 and 2014 , the Company had only one customer other than the affiliate transactions that individually represented greater than 10.0% of its consolidated midstream revenues. The customer is located in the Louisiana segment and represented 11.7% and 11.0% , of the consolidated revenues for the year ended December 31, 2015 and 2014 , respectively. The affiliate transactions with Devon represented 16.6% , 30.6% and 92.2% of the consolidated midstream revenues for the years ended December 31, 2015 , 2014 and 2013 , respectively. As the Company continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. Devon and the Company's Louisiana customer represent a significant percentage of revenues and the loss of either customer would have a material adverse impact on the Company's results of operations because the gross operating margin received from transactions with these customers is material to the Company. (o) Environmental Costs Environmental expenditures are expensed or capitalized as depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental expenditures were $3.5 million for the year ended December 31, 2015. For December 31, 2014 and 2013, such expenditures were not material. (p) Unit-Based Awards Prior to the business combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon's U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods. The Company recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with FASB ASC 718. The Company and the Partnership each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC's unit-based compensation plans awarded to directors, officers and employees of the general partner of the Partnership are recorded by the Partnership since the Company has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings. (q) Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. (r) Discontinued Operations The Company classifies as discontinued operations its assets that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Company also includes as discontinued operations Predecessor assets that were not contributed in the business combination. (s) Other Assets Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $23.8 million and $17.5 million as of December 31, 2015 and 2014, respectively, are included in other assets, net. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the debt. (t) Legal Costs Expected to be Incurred in Connection with a Loss Contingency Legal costs incurred in connection with a loss contingency are expensed as incurred. (u) Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder's share of net income or loss and distributions). (v) Recent Accounting Pronouncements In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). Under this new standard, the FASB issued new guidance related to accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. ASU 2016-01 is effective beginning after December 15, 2017 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). The new standard requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective in fiscal years beginning after December 15, 2016, including interim periods within those years. Early adoption is permitted. ASU 2015-17 may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively. We are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures. In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”) which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the standard will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and will have no impact on our consolidated financial statements but will require to provide additional disclosure to our footnotes. Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the year ended December 31, 2015, and have determined that none would have a material impact on our Consolidated Financial Statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Acquisitions	Acquisitions Chevron acquisition On November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the equity interests (all of which were voting) in certain entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Property, plant and equipment $ 225.3 Intangibles 13.0 Liabilities assumed: Current liabilities (6.8 ) Total purchase price $ 231.5 The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 20 years. The Partnership incurred $0.6 million of direct transaction costs for the year ended December 31, 2015 . These costs are included in general and administrative costs in the accompanying Consolidated Statements of Operations. LPC Acquisition On January 31, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million ( $87.0 million , net of cash acquired). The transaction was accounted for using the acquisition method. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Current assets (including $21.1 million in cash) $ 107.4 Property, plant and equipment 29.8 Intangibles 43.2 Goodwill 29.6 Liabilities assumed: Current liabilities (97.9 ) Deferred tax liability (4.0 ) Total identifiable net assets $ 108.1 The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships will be amortized on a straight-line basis over the estimated customer life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Crude and Condensate segment and is non-deductible for tax purposes. The Partnership incurred $0.3 million of direct transaction costs for the year ended December 31, 2015 . These costs are included in general and administrative costs in the accompanying Consolidated Statements of Operations. For the period from January 31, 2015 to December 31, 2015 , the Partnership recognized $1.1 billion of revenues and $0.9 million of net income related to the assets acquired. Coronado Acquisition On March 16, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million . The purchase price consisted of $240.3 million in cash ( $238.9 million , net of cash acquired), 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Current assets (including $1.4 million in cash) $ 20.8 Property, plant and equipment 302.1 Intangibles 281.0 Goodwill 18.7 Liabilities assumed: Current liabilities (22.3 ) Total identifiable net assets $ 600.3 The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership's Texas segment and is non-deductible for tax purposes. The Partnership incurred $3.1 million of direct transaction costs for the year ended December 31, 2015 . These costs are included in general and administrative costs in the accompanying Consolidated Statements of Operations. For the period from March 16, 2015 to December 31, 2015 , the Partnership recognized $182.0 million of revenues and $14.2 million of net loss related to the assets acquired. Matador Acquisition On October 1, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $145.3 million . The transaction was accounted for using the acquisition method. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. Purchase Price Allocation (in millions): Assets acquired: Current assets $ 1.9 Property, plant and equipment 35.5 Intangibles 98.8 Goodwill 9.1 Total identifiable net assets $ 145.3 The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 20 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership's Texas segment and is non-deductible for tax purposes. The Parthernship incurred $0.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying Consolidated Statements of Operations. For the period from October 1, 2015 to December 31, 2015, the Partnership recognized $5.6 million of revenues and $0.7 million of net loss related to the assets acquired. Deadwood Acquisition Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, the Partnership acquired Apache's 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.0 million , all of which is considered property, plant and equipment. The transaction was accounted for using the acquisition method. Direct transaction costs attributable to this acquisition were less than $0.1 million . For the period from November 16, 2015 to December 31, 2015, the Partnership recognized $3.5 million of revenues and $1.3 million of net income related to the assets acquired. VEX Pipeline Drop Down On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in south Texas, together with 100% of the equity interests (all of which were voting) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”). The aggregate consideration paid by the Partnership consisted of $166.7 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX Interests were recorded on the Partnership's books at historical cost on the date of transfer of $131.0 million . The difference between the historical cost of the net assets and consideration given was $35.7 million and is recognized as a distribution to Devon. Construction costs paid by Devon during the first quarter of 2015 totaling $25.6 million are reflected as contributions from Devon to the Partnership in our Consolidated Statements of Changes in Members' Equity and Consolidated Statements of Cash Flows for the year ended December 31, 2015. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon. The following tables present the impact of the VEX Drop Down as presented in the Company's historical Consolidated Statements of Operations for the years ended December 31, 2015 and 2014 . Year Ended December 31, 2015 Company Historical VEX Combined (in millions) Revenues $ 4,446.8 $ 5.3 $ 4,452.1 Net income (loss) $ (1,411.5 ) $ 1.8 $ (1,409.7 ) Net loss attributable to non-controlling interest $ (1,054.5 ) $ — $ (1,054.5 ) Net income (loss) attributable to EnLink Midstream, LLC $ (357.0 ) $ 1.8 $ (355.2 ) EnLink Midstream, LLC interest in net loss $ (357.0 ) $ — $ (357.0 ) Year Ended December 31, 2014 Company Historical VEX** Combined (in millions) Revenues $ 3,500.4 $ 7.4 $ 3,507.8 Net income (loss) $ 252.7 $ (2.0 ) $ 250.7 Net income attributable to non-controlling interest $ 126.7 $ — $ 126.7 Net income (loss) attributable to EnLink Midstream, LLC $ 126.0 $ (2.0 ) $ 124.0 EnLink Midstream, LLC interest in net income $ 90.5 $ — $ 90.5 ____________________________________________________________________________ ** The VEX amounts reflect the period from February 28, 2014 (the date VEX was acquired by Devon) through December 31, 2014. Devon Merger On March 7, 2014 , EMI merged with and into a wholly-owned subsidiary of the Company, and New Acacia, formerly a wholly-owned subsidiary of Devon, merged with and into another wholly-owned subsidiary of the Company (collectively, the “mergers”). Upon consummation of the mergers, EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. As of December 31, 2014, the Company, through its ownership of EMI, owned approximately 7.1% of the outstanding limited partner interests in the Partnership and owned 100.0% of the General Partner. The Company, through its ownership of New Acacia, indirectly owns a 50% limited partner interest in Midstream Holdings. Midstream Holdings owns midstream assets previously held by Devon in the Barnett Shale in North Texas, the Cana-Woodford Shale and Arkoma-Woodford Shale in Oklahoma and a contractual right to the burdens and benefits associated with Devon’s 38.75% interest in Gulf Coast Fractionators (“GCF”) in Mt. Belvieu, Texas. Also effective as of March 7, 2014, a wholly-owned subsidiary of the Partnership acquired the remaining 50% limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). Under the acquisition method of accounting, Midstream Holdings is the acquirer in the business combination because its parent company, Devon, obtained control of ENLC. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC’s non-controlling interest in the Partnership, are recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired is recorded as goodwill. Since equity consideration was issued for this business combination, the purchase of these assets and liabilities has been excluded from our statement of cash flows, except for transaction related costs totaling $51.4 million assumed by ENLC at closing and subsequently paid by ENLC. Unaudited Pro Forma Information The following unaudited pro forma condensed financial information for the years ended December 31, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, Matador acquisition and VEX Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Pro forma financial information associated with the business combination and acquisitions is reflected below. Year Ended December 31, 2015 2014 (in millions except for per unit data) Pro forma total revenues (1) $ 4,585.5 $ 5,679.3 Pro forma net income (loss) $ (1,413.0 ) $ 220.2 Pro forma net income (loss) attributable to Enlink Midstream, LLC $ (355.5 ) $ 64.8 Pro forma net income (loss) per common unit: Basic $ (2.18 ) $ 0.41 Diluted $ (2.18 ) $ 0.41 ____________________________________________________________________________ (1) On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill [Line Items]
Goodwill and Intangible Assets	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. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During September 2015, we determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in the Partnership's unit price caused a change in circumstances warranting an interim impairment test at the Partnership level. We also performed an annual impairment analysis for both the Company and the Partnership during the fourth quarter of 2015. Although our established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015 due to continued declines in commodity prices and our unit prices during the fourth quarter of 2015. We and the Partnership perform our goodwill assessments at the reporting unit level. The Partnership uses 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 forecasts and price and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market information, among other factors. We also have goodwill related to our investment in the Partnership that is included in our Corporate segment. We utilize the publicly traded market value of our common units, adjusted for our estimated control premium, in our Corporate level goodwill assessment. Using the fair value approaches described above, in step one of the goodwill impairment test, the Partnership determined that the estimated fair value of its Louisiana, Texas and Crude and Condensate reporting units were less than their carrying amounts, primarily due to changes in assumptions related to commodity prices, volume forecasts and discount rates. The second step of the goodwill impairment test measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for its Louisiana, Texas and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015, which is included in impairment expense in the Consolidated Statements of Operations. We and the Partnership concluded that the fair value of goodwill of the Oklahoma and Corporate reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the Consolidated Balance Sheet associated with this remaining reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our annual goodwill assessment. The Partnership's impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with the Partnership's assumptions and estimates, or its assumptions and estimates change due to new information, the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value for a reporting unit exceeds fair value. A continuing prolonged period of lower commodity prices may adversely affect the Partnership's estimates of future operating results and the Partnership's unit price, which could result in future goodwill impairment charges for the Partnership's Texas and Crude and Condensate reporting units due to the potential impact on the cash flows of its operations. In addition, significant decreases to our unit price could result in an impairment charge to our Corporate reporting unit. The table below provides a summary of the Partnership’s change in carrying amount of goodwill, by assigned reporting unit. Texas Louisiana Oklahoma Crude and Condensate Corporate Totals (in millions) Year Ended December 31, 2015 Balance, beginning of period $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 Acquisitions (1) 27.8 — — 29.6 — 57.4 Impairment (492.5 ) (786.8 ) — (48.9 ) — (1,328.2 ) Balance, end of period $ 703.5 $ — $ 190.3 $ 93.2 $ 1,426.9 $ 2,413.9 Year Ended December 31, 2014 Balance, beginning of period $ 325.4 $ — $ 76.3 $ — $ — $ 401.7 Acquisitions (1) 842.8 786.8 114.0 112.5 1,426.9 3,283.0 Balance, end of period $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 ____________________________________________________________________________ (1) See Note 3-Acquisitions for further discussion. 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 10 to 20 years. During 2015, the Partnership reviewed our various assets groups for impairment due to the triggering events described in the goodwill impairment analysis above. The undiscounted cash flows related to one of the Partnership's asset groups in the Crude and Condensate segment were not in excess of its related carrying value. The Partnership estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of their carrying value. This resulted in a $223.1 million impairment of intangible assets in our Crude and Condensate segment. The non-cash impairment charge is included in the impairment expense line item of the Consolidated Statement of Operations. The Partnership utilized Level 3 fair value measurements in our impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in the Partnership's goodwill impairment analysis. The following table represents the Partnership's change in carrying value of intangible assets for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2015 Customer relationships, beginning of period $ 569.5 $ (36.5 ) $ 533.0 Acquisitions 436.0 — 436.0 Amortization expense — (56.0 ) (56.0 ) Impairment (261.0 ) 37.9 (223.1 ) Customer relationships, end of period $ 744.5 $ (54.6 ) $ 689.9 Year Ended December 31, 2014 Customer relationships, beginning of period $ — $ — $ — Acquisitions 569.5 — 569.5 Amortization expense — (36.5 ) (36.5 ) Customer relationships, end of period $ 569.5 $ (36.5 ) $ 533.0 The weighted average amortization period for intangible assets is 12.6 years. Amortization expense for intangibles was approximately $56.0 million and $36.5 million for the years ended December 31, 2015 and 2014 , respectively. The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions): 2016 $ 46.1 2017 46.1 2018 46.1 2019 46.1 2020 46.1 Thereafter 459.4 Total $ 689.9

Affiliate Transactions

Affiliate Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Affiliate Transactions	Affiliate Transactions The Partnership engages in various transactions with Devon and other affiliated entities. For the years ended December 31, 2015 , 2014 and 2013 , Devon was a significant customer to the Partnership. Devon accounted for 16.6% , 30.6% and 92.2% of the Partnership's revenues for the year ended December 31, 2015 , 2014 and 2013 , respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $110.8 million and $121.6 million as of December 31, 2015 and 2014 , respectively. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $14.8 million and $3.0 million as of December 31, 2015 and 2014 , respectively. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements. Gathering, Processing and Transportation Agreements with Devon As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. On January 1, 2014, in connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings (“EnLink Midstream Services”), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon (“Gas Services”), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering systems in the Barnett Shale. These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law. The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause. In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline. Effective December 1, 2014, Gas Services assigned one of its 10-year gathering and processing agreements to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, beginning on December 1, 2014, Linn Energy assumed all right, title and interest in the gathering and processing agreement and began performing Gas Services' obligations under the agreement, which relates to production dedicated to our Northridge assets in southeastern Oklahoma and remains in full force and effect. Other Commercial Relationships with Devon As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. The terms of these agreements vary, but the agreements expire between January 2016 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee. These NGL, gas and crude oil purchase and sale agreements have month-to-month terms. VEX Transportation Agreement In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline. Transition Services Agreement In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.2 million and $3.0 million for years ended December 31, 2015 and 2014 , respectively. We received $0.3 million from Devon under the transition services agreement for the year ended December 31, 2015 and 2014 , respectively. EMH Drop Down to Partnership On February 17, 2015, Acacia contributed the February Transferred Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million . The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015. On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million . The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. E2 Drop Down to Partnership On October 22, 2014, EMI contributed its equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) to the Partnership in a drop down transaction (the “E2 Drop Down”). The total consideration for the transaction was approximately $194.0 million , including a cash payment of $163.0 million and the issuance of approximately 1.0 million Partnership units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the Partnership's units). Predecessor Affiliate Transactions Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates. The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions): Year Ended December 31, 2014 2013 Continuing Operations: Operating revenues - affiliates $ (436.4 ) $ (2,116.5 ) Operating expenses - affiliates 340.0 1,669.5 Net affiliate transactions (96.4 ) (447.0 ) Capital expenditures 16.2 244.3 Other third-party transactions, net 58.9 51.5 Net third-party transactions 75.1 295.8 Net cash distributions to Devon - continuing operations (21.3 ) (151.2 ) Non-cash distribution of net assets to Devon (6.3 ) — Total net distributions per equity $ (27.6 ) $ (151.2 ) Discontinued operations: Operating revenues - affiliates $ (10.4 ) $ (84.6 ) Operating expenses - affiliates 5.0 32.7 Cash used in financing activities - affiliates — (5.6 ) Net affiliate transactions (5.4 ) (57.5 ) Capital expenditures 0.6 1.1 Other third-party transactions, net 0.4 (72.0 ) Net third-party transactions 1.0 (70.9 ) Net distributions to Devon and non-controlling interests - discontinued operations (4.4 ) (128.4 ) Non-cash distribution of net assets to Devon (39.9 ) — Total net distributions per equity $ (44.3 ) $ (128.4 ) Total distributions- continuing and discontinued operations (1) $ (71.9 ) $ (279.6 ) ____________________________________________________________________________ (1) Total distributions- continuing and discontinued operations for the year ended December 31, 2013 of $279.6 million does not include $5.5 million of distributions related to certain assets that weren't transferred to the Partnership, which are included in the Distribution to Predecessor line item on the Consolidated Statements of Changes in Members' Equity. Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million and $12.8 million for the years ended December 31, 2014 and 2013, respectively. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million and $8.7 million for the years ended December 31, 2014 and 2013, respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt As of December 31, 2015 and 2014 , long-term debt consisted of the following (in millions): Year Ended December 31, 2015 2014 Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at December 31, 2015 and December 31, 2014 was 1.8% and 1.9%, respectively $ 414.0 $ 237.0 Credit facility (due 2019) — — The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at December 31, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70% 399.6 399.5 The Partnership's senior unsecured notes (due 2022), including a premium of $18.9 million at December 31, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125% 181.4 184.4 The Partnership's senior unsecured notes (due 2024), net of premium of $2.9 million at December 31, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40% 552.9 553.2 The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at December 31, 2015, which bear interest at the rate of 4.15% 748.8 — The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at December 31, 2015 and $0.3 million at December 31, 2014, which bear interest at the rate of 5.60% 349.8 349.7 The Partnership's senior unsecured notes (due 2045), net of discount of $6.9 million at December 31, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05% 443.1 298.3 Other debt 0.2 0.4 Debt classified as long-term $ 3,089.8 $ 2,022.5 Maturities. Maturities for the long-term debt as of December 31, 2015 are as follows (in millions): 2016 $ 0.1 2017 0.1 2018 — 2019 400.0 2020 414.0 Thereafter 2,262.5 Subtotal 3,076.7 Add: net premium 13.1 Total outstanding debt $ 3,089.8 Company Credit Facility . On March 7, 2014, the Company entered into a new $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 Partnership 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 any additional equity interests subsequently pledged as collateral under the credit facility. The credit facility will mature on March 7, 2019 . The 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 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 credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the 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 at all times unless an investment grade event (as defined in the credit facility) occurs. Borrowings under the credit facility bear interest, at our option, at either the Eurodollar Rate (the LIBOR Rate) plus an applicable margin 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. The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing the credit facility could be foreclosed upon. At December 31, 2015, the Company was in compliance and expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months. As of December 31, 2015, there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million . Partnership Credit Facility. On February 20, 2014 , the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership 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 Partnership credit facility by an additional amount not to exceed $500 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year on each occasion. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the Partnership 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 Partnership credit facility bear interest at the Partnership’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin 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 as listed below. The applicable margins vary depending on the Partnership’s credit rating. If the Partnership breaches certain covenants governing the Partnership credit facility, amounts outstanding under the Partnership credit facility, if any, may become due and payable immediately. At December 31, 2015, the Partnership was in compliance and expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months. As of December 31, 2015 , there were $10.9 million in outstanding letters of credit and $414.0 million in outstanding borrowings under the Partnership credit facility, leaving approximately $1.1 billion available for future borrowing based on the borrowing capacity of $1.5 billion . Pricing Level Debt Ratings Applicable Rate Commitment Fee EuroDollar Rate/Letter of Credit Base Rate + 1 A-/A3 or better 0.100% 1.000% —% 2 BBB+/Baa1 0.125% 1.125% 0.125% 3 BBB/Baa2 0.175% 1.250% 0.250% 4 BBB-/Baa3 0.225% 1.500% 0.500% 5 BB+/Ba1 0.275% 1.625% 0.625% 6 BB/Ba2 or worse 0.350% 1.750% 0.750% Senior Unsecured Notes. On March 7, 2014, the Partnership recorded $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “2018 Notes”) due on February 15, 2018 in the business combination. As a result of the business combination, the 2018 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $761.3 million , including a premium of $36.3 million , as of March 7, 2014. On March 7, 2014, the Partnership recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 in the business combination. The interest payments on the 2022 Notes are due semi-annually in arrears in June and December. As a result of the business combination, the 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million , including a premium of $29.5 million . On July 20, 2014 , the Partnership redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million , including accrued interest. On September 20, 2014 , the Partnership redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million , including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2022 Notes of $2.4 million for the year ended December 31, 2014. On March 12, 2014 , the Partnership commenced a tender offer to purchase any and all of the outstanding 2018 Notes. Approximately $536.1 million , or approximately 74% , of the 2018 Notes were validly tendered and on March 19, 2014 , the Partnership made a payment of approximately $567.4 million for all such tendered 2018 Notes. Also on March 19, 2014 , the Partnership delivered a notice of redemption for any and all outstanding 2018 Notes. All remaining outstanding 2018 Notes were redeemed on April 18, 2014 for $200.2 million , including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2018 Notes of $0.7 million for the year ended December 31, 2014. On March 19, 2014 , the Partnership issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of its 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “2024 Notes”) and $350.0 million aggregate principal amount of its 5.600% senior notes due 2044 (the “2044 Notes”), at prices to the public of 99.850% , 99.830% and 99.925% , respectively, of their face value. The 2019 Notes mature on April 1, 2019 , the 2024 Notes mature on April 1, 2024 and the 2044 Notes mature on April 1, 2044 . The interest payments on the 2019 Notes, 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October. On November 12, 2014 , the Partnership issued an additional $100.0 million aggregate principal amount of its 2024 Notes and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 notes”), at prices to the public of 104.007% and 99.452% , respectively, of their face value. The new 2024 Notes were offered as an additional issue of the Partnership’s outstanding 4.400% Senior Notes due 2024, issued in an aggregate principal amount of $450.0 million on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October. On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of its 2045 Notes at prices to the public of 99.827% and 96.381% , respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of our outstanding 5.050% Senior Notes due 2045, issued in an aggregate principal amount of $300.0 million on November 12, 2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date. Prior to J une 1, 2017 , the Partnership may redeem all or part of the remaining 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date. On or after June 1, 2017, the Partnership may redeem all or a part of the remaining 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017 , 102.375% for the twelve-month period beginning on June 1, 2018 , 101.188% for the twelve-month period beginning on June 1, 2019 and 100% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes. Prior to March 1, 2019 , the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2019 Notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the 2019 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2019 , the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. Prior to January 1, 2024 , the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2024 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 25 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after January 1, 2024 , the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to 100% of the principal amount of the 2024 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. Prior to March 1, 2025, the Partnership may redeem all or part of the 2025 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the Partnership may redeem all or part of the 2025 Notes at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. Prior to October 1, 2043 , the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2044 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2044 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2043 , the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to 100% of the principal amount of the 2044 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. Prior to October 1, 2044 , the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2045 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2045 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2044 , the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to 100% of the principal amount of the 2045 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. The indentures governing the senior notes contain covenants that, among other things, limit our ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of our assets. Each of the following is an event of default under the indentures: • failure to pay any principal or interest when due; • failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures; and • bankruptcy or other insolvency events involving us. If an event of default relating to bankruptcy or other insolvency events occurs, the senior notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies. At December 31, 2015, the Partnership was in compliance and expects to be in compliance with the covenants in the Senior Notes for at least the next twelve months.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes All taxes presented prior to March 7, 2014 relate to the predecessor’s results of continuing operations. Taxes presented for the periods subsequent to March 6, 2014 relate to the combined operations of ENLC, Predecessor and the remaining underlying operating entities. ENLC files a consolidated federal income tax return, which includes the results of operations on its two underlying corporate subsidiaries. Income taxes are calculated based on each entity's separate taxable income or loss. The provision for income taxes is comprised of the following (in millions): Year Ended December 31, 2015 2014 2013 Current tax expense $ 3.1 $ 9.0 $ 31.5 Deferred tax expense 22.6 67.4 35.5 Total income tax expense $ 25.7 $ 76.4 $ 67.0 The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows: Year Ended December 31, 2015 2014 2013 Expected income tax expense (benefit) based on federal statutory rate of 35% $ (116.0 ) $ 70.7 $ 65.1 State income taxes, net of federal benefit and other (7.7 ) 5.7 1.9 Goodwill impairment 149.4 — — Total income tax expense $ 25.7 $ 76.4 $ 67.0 Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 2015 and 2014 are as follows: Year Ended December 31, 2015 2014 Deferred income tax assets: Federal net operating loss carryforward, current $ — $ 16.9 Total current deferred tax assets — 16.9 Asset retirement obligations and other 2.3 2.0 State net operating loss carryforward, non current 3.6 4.2 Federal net operating loss carryforward, non current 20.9 — Total non current deferred tax assets 26.8 6.2 Total deferred tax assets 26.8 23.1 Deferred tax liabilities: Property, plant, equipment, and intangible assets, non current (557.6 ) (523.5 ) Other (1.3 ) (9.3 ) Total non current deferred tax liabilities (558.9 ) (532.8 ) Deferred tax liability, net $ (532.1 ) $ (509.7 ) At December 31, 2015, we had federal net operating loss carryforwards of $59.8 million that represent a net deferred tax asset of $20.9 million . At December 31, 2015, we had state net operating loss carryforwards of $141.0 million that represent a net deferred tax asset of $3.6 million . These carryforwards will begin expiring in 2028 through 2035. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire. As of December 31, 2015, the total amount of unrecognized tax benefits was $1.5 million . A reconciliation of the beginning and ending amount of the unrecognized tax benefits is as follows (in millions): Year Ended December 31, 2015 2014 Balance at January 1 $ 2.0 $ — Unrecognized tax positions assumed in merger — 3.8 Decrease due to prior year tax positions (0.5 ) (2.0 ) Increases due to current year tax positions — 0.2 Balance at December 31 $ 1.5 $ 2.0 Unrecognized tax benefits as of December 31, 2015 of $1.5 million , if recognized, would affect the effective tax rate. It is unknown when the remaining uncertain tax positions will be resolved. Per the Company's accounting policy election, penalties and interest related to prior year tax positions are recorded to income tax expense. As of December 31, 2015, tax years 2011 through 2015 remain subject to examination by various state taxing authorities.

Certain Provisions of the Partn

Certain Provisions of the Partnership Agreement	12 Months Ended
	Dec. 31, 2015
Partners' Capital [Abstract]
Certain Provisions of the Partnership Agreement	Certain Provisions of the Partnership Agreement (a) Issuance of Common Units In November 2014, the Partnership issued 12,075,000 common units representing limited partner interests in the Partnership at an offering price of $28.37 per unit for net proceeds of $332.3 million . The net proceeds from the common units offering were used for capital expenditures and general partnership purposes. In October 2014, the Partnership issued 1,016,322 common units to ENLC representing limited partner interests in the Partnership as partial consideration for E2 acquisition. In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million . Through December 31, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating proceeds of approximately $71.9 million (net of approximately $0.7 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes. On November 7, 2014 , Partnership entered into an Equity Distribution Agreement (the “BMO 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 (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units representing limited partner interests from time to time through an “at the market” equity offering program. The Partnership 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. The Partnership has no obligation to sell any of the Common Units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the year ended December 31, 2015, the Partnership sold an aggregate of 1.3 million common units under the BMO EDA, generating proceeds of approximately $24.4 million (net of approximately $0.3 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of December 31, 2015, approximately $317.0 million of common units remain available to be issued under the BMO EDA. On October 29, 2015, the Partnership issued 2,849,100 common units at an offering price of $17.55 per unit to a subsidiary of ENLC for aggregate consideration of approximately $50.0 million in a private placement transaction. (b) Class C Common Units In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. For further discussion, see Note 3- Acquisitions. The Class C Common Units are substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units may be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on the earlier to occur of (i) the date on which the General Partner, in its sole discretion, determines to convert all of the outstanding Class C Common Units into common units and (ii) the first business day following the date of the distribution for the quarter ended March 31, 2016. Distributions on the Class C Common Units for the three months ended March 31, 2015, June 30, 2015, and September 30, 2015 were paid-in-kind (“PIK”) through the issuance of 99,794 , 120,622 , and 150,732 Class C Common Units on May 14, 2015, August 13, 2015, and November 12, 2015, respectively. A distribution on the Class C Common Units of $0.390 per unit was declared for the three months ended December 31, 2015, which will result in the issuance of 209,044 additional Class C Common Units on February 11, 2016. (c) Class D Common Units In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion, see Note 3 - Acquisitions. The Partnership’s Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. The Partnership’s Class D Common Units automatically converted into the Partnership’s common units on a one-for-one basis on May 4, 2015. (d) Class E Common Units In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion, see Note 5 - Affiliate Transactions. The Partnership’s Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015. (e) Distributions Unless restricted by the terms of the Partnership's credit facility and/or the indentures governing the Partnership’s senior unsecured notes, the Partnership must make distributions of 100% of available cash, as defined in the 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 its general partner or incentive distributions with respect to the Class C Common Units issued in kind. Under the quarterly incentive distribution provisions, generally the Partnership's General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit. Incentive distributions totaling $47.5 million were earned by our general partner for the year ended December 31, 2015 . The Partnership paid annual distributions per common unit of $1.53 for the year ended December 31, 2015 . A summary of the Partnership's distribution activity relating to the common units for the years ended December 31, 2015 and 2014 is provided below: Declaration period Distribution/unit Date paid/payable 2015 First Quarter of 2015 (1) $ 0.380 May 14, 2015 Second Quarter of 2015 (2) $ 0.385 August 13, 2015 Third Quarter of 2015 $ 0.390 November 12, 2015 Fourth Quarter of 2015 $ 0.390 February 11, 2016 2014 First Quarter of 2014 (3) $ 0.360 May 14, 2014 Second Quarter of 2014 $ 0.365 August 13, 2014 Third Quarter of 2014 $ 0.370 November 13, 2014 Fourth Quarter of 2014 $ 0.375 February 12, 2015 ____________________________________________________________________________ (1) The Partnership's partial first quarter 2015 distributions on its Class D Common Units of $0.18 per unit were paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015. (2) The Partnership's partial second quarter 2015 distributions on its Class E Common Units of $0.15 per unit were paid on August 13, 2015. Distributions paid for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015. (3) The Partnership's first quarter 2014 distributions on its Class B Common Units of $0.10 per unit were paid on May 14, 2014. Distributions declared for the Class B Common Units represent a pro rata distribution for the number of days the Class B Common Units were issued and outstanding during the quarter. The Class B Common Units automatically converted into common units on a one-for-one basis on May 6, 2014. (f) Allocation of Partnership Income Net income is allocated to the General Partner in an amount equal to its incentive distribution as described in Note 8(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’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): Year Ended December 31, 2015 2014 Income allocation for incentive distributions $ 47.5 $ 20.6 Unit-based compensation attributable to ENLC’s restricted units (18.3 ) (10.4 ) General Partner share of net income (loss) (6.7 ) 1.1 General Partner interest in drop down transactions 35.5 127.0 General Partner interest in net income (loss) $ 58.0 $ 138.3

Earnings per Unit and Dilution

Earnings per Unit and Dilution Computations	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per Unit and Dilution Computations	Earnings per Unit and Dilution Computations As required under FASB ASC 260-10-45-61A, unvested unit-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders. Net income (loss) attributable to the VEX Interests acquired from Devon, respectively, for periods prior to acquisition are not allocated for purposes of calculating net income (loss) per common unit. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions except per unit amounts): Year Ended December 31, 2015 2014* Net income attributable to Enlink Midstream, LLC $ (357.0 ) $ 90.5 Distributed earnings allocated to: Common units (1) (2) $ 165.0 $ 126.8 Unvested restricted units (1) 1.1 0.8 Total distributed earnings $ 166.1 $ 127.6 Undistributed loss allocated to: Common units (2) $ (519.5 ) $ (36.9 ) Unvested restricted units (3.6 ) (0.2 ) Total undistributed loss $ (523.1 ) $ (37.1 ) Net income (loss) allocated to: Common units (2) $ (354.5 ) $ 89.9 Unvested restricted units (2.5 ) 0.6 Total net income (loss) $ (357.0 ) $ 90.5 Total basic and diluted net income (loss) per unit: Basic $ (2.17 ) $ 0.55 Diluted $ (2.17 ) 0.55 ____________________________________________________________________________ * The 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014. (1) The December 31, 2015 and 2014 amount represents a declared distribution of $0.255 per unit payable February 12, 2016 , and distributions paid of $0.245 per unit on May 15, 2015, $0.25 per unit on August 14, 2015, $0.255 per unit on November 13, 2015, $0.18 per unit on May 15, 2014, $0.22 per unit on August 13, 2014, $0.23 per unit on November 14, 2014, and $0.235 per unit on on February 13, 2015. (2) The 2014 amount includes distribution of $0.05 per unit for Class B Units paid on May 15, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014. The following are the unit amounts used to compute the basic and diluted earnings per unit for the years ended December 31, 2015 and 2014 (in millions): Year Ended December 31, 2015 2014 Basic weighted average units outstanding: Weighted average common units outstanding 164.2 164.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 164.2 164.0 Dilutive effect of restricted incentive units issued — 0.3 Total weighted average diluted common units outstanding 164.2 164.3 All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. All common unit equivalents were antidilutive for the year ended December 31, 2015 because common units were allocated a net loss.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The schedule below summarizes the changes in the Partnership’s asset retirement obligations: Year Ended December 31, 2015 2014 (in millions) Beginning asset retirement obligation $ 20.6 $ 7.7 Revisions to existing liabilities (4.0 ) 2.2 Liabilities acquired — 10.2 Accretion 0.6 0.5 Liabilities settled (3.2 ) — Ending asset retirement obligation $ 14.0 $ 20.6 Asset retirement obligations of $1.1 million and $8.2 million as of December 31, 2015 and 2014 , respectively, are included in Other Current Liabilities.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	Investment in Unconsolidated Affiliates The Partnership’s unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in GCF at December 31, 2015 , 2014 and 2013 , and a 30.6% ownership interest in Howard Energy Partners (“HEP”) at December 31, 2015 and 2014 . The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): Gulf Coast Fractionators Howard Energy Partners (1) Total December 31, 2015 Contributions $ — $ 25.8 $ 25.8 Distributions $ 14.5 $ 28.2 $ 42.7 Equity in income $ 13.0 $ 7.4 $ 20.4 December 31, 2014 (1) Contributions $ — $ 5.7 $ 5.7 Distributions $ 11.0 $ 12.7 $ 23.7 Equity in income $ 17.1 $ 1.8 $ 18.9 December 31, 2013 Distributions $ 12.0 $ — $ 12.0 Equity in income $ 14.8 $ — $ 14.8 ____________________________________________________________________________ (1) Includes income, distributions, and contributions for the period from March 7, 2014 through December 31, 2014. The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2015 2014 Gulf Coast Fractionators (1) $ 52.6 $ 54.1 Howard Energy Partners 221.7 216.7 Total investments in unconsolidated affiliates $ 274.3 $ 270.8 ____________________________________________________________________________ (1) Devon retained $13.1 million of the undistributed earnings due from GCF, as of March 7, 2014 when the GCF contractual right allocating the benefits and burdens of the 38.75% ownership interest in GCF to the Partnership became effective. The $13.1 million of the undistributed earnings was reflected as a reduction in the GCF investment on March 7, 2014.

Employee Incentive Plans

Employee Incentive Plans	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Incentive Plans	Employee Incentive Plans (a) Long-Term Incentive Plans The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements. The Partnership and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below. Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions): Year Ended December 31, 2015 2014 2013 Cost of unit-based compensation allocated to Predecessor general and $ — $ 2.8 $ 12.8 Cost of unit-based compensation charged to general and administrative expense 31.1 16.9 — Cost of unit-based compensation charged to operating expense 5.0 2.7 — Total amount charged to income $ 36.1 $ 22.4 $ 12.8 Interest of non-controlling partners in unit-based compensation $ 14.0 $ 8.3 $ — Amount of related income tax expense recognized in income $ 8.3 $ 5.3 $ 4.8 ____________________________________________________________________________ (1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity. On March 7, 2014, the General Partner amended and restated the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”) (formerly the Crosstex Energy GP, LLC Long-Term Incentive Plan). Amendments to the Plan included a change in name and other technical amendments. The Plan provides for the issuance of up to 9,070,000 ENLK common units. (b) Restricted Incentive Units The restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 2015 is provided below: EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,022,191 $ 31.25 Granted 596,508 26.50 Vested* (281,319 ) 28.79 Forfeited (83,651 ) 30.55 Non-vested, end of period 1,253,729 $ 29.59 Aggregate intrinsic value, end of period (in millions) $ 20.8 ____________________________________________________________________________ * Vested units include 95,127 units withheld for payroll taxes paid on behalf of employees. The Partnership issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of 3 years . In March 2015, the Partnership issued 128,675 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above. A summary of the restricted incentive units' aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2015 and 2014 are provided below (in millions): Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2015 2014 Aggregate intrinsic value of units vested $ 7.5 $ 1.8 Fair value of units vested $ 8.1 $ 1.9 As of December 31, 2015 , there was $16.2 million of unrecognized compensation cost related to Partnership non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.6 years . (c) EnLink Midstream Partners, LP Performance Units In March 2015, the Partnership and ENLC granted performance awards under the 2014 Long-Term Incentive Plan (the “2014 Plan”) and GP 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 the Partnership and the Company (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (the “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 with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on the EnLink TSR as compared to the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions. EnLink Midstream Partners, LP Performance Units: 2015 Beginning TSR Price $ 27.68 Risk-free interest rate 0.99 % Volatility factor 33.01 % Distribution yield 5.66 % The following table presents a summary of the Partnership's performance units. Year Ended EnLink Midstream Partners, LP Performance Units: Number of Weighted Non-Vested, beginning of period — $ — Granted 118,126 35.41 Vested — — Non-vested, end of period 118,126 $ 35.41 Aggregate intrinsic value, end of period (in millions) $ 2.0 As of December 31, 2015 , there was $3.0 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of two years . (d) EnLink Midstream, LLC’s Restricted Incentive Units On February 5, 2014, ENLC's sole unitholder at the time, EnLink Midstream Manager, LLC, approved the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “Company Plan”). The Company Plan provides for the issuance of 11,000,000 common units. On March 7, 2014, effective as of the closing of the business combination, ENLC (i) assumed the Crosstex Energy, Inc. 2009 Long-Term Incentive Plan (the “2009 Plan”) and all awards thereunder outstanding following the business combination and (ii) amended and restated the 2009 Plan to reflect the conversion of the awards under the 2009 Plan relating to EMI’s common stock to awards in respect of common units of ENLC. ENLC’s 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 activities for the year ended December 31, 2015 is provided below: EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 986,472 $ 37.03 Granted 508,101 31.12 Vested* (273,791 ) 35.87 Forfeited (71,889 ) 35.55 Non-vested, end of period 1,148,893 $ 34.78 Aggregate intrinsic value, end of period (in millions) $ 17.3 ____________________________________________________________________________ * Vested units include 86,635 units withheld for payroll taxes paid on behalf of employees. ENLC issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of 3 years and are included in restricted incentive units outstanding. In March 2015, ENLC issued 102,543 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above. A summary of the restricted units' aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2015 and 2014 are provided below (in millions): Year Ended December 31, EnLink Midstream LLC Restricted Incentive Units: 2015 2014 Aggregate intrinsic value of units vested $ 9.2 $ 3.1 Fair value of units vested $ 9.8 $ 2.9 As of December 31, 2015 there was $16.6 million of unrecognized compensation costs related to ENLC non-vested restricted incentive units for directors, officers and employees. The cost is expected to be recognized over a weighted average period of 1.6 years. (e) EnLink Midstream, LLC's Performance Units In March 2015, ENLC granted performance awards under the 2014 Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group 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 and the designated peer group; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions. EnLink Midstream, LLC Performance Units: 2015 Beginning TSR Price $ 34.24 Risk-free interest rate 0.99 % Volatility factor 33.02 % Distribution yield 2.98 % The following table presents a summary of the Company's performance units. Year Ended EnLink Midstream, LLC Performance Units: Number of Weighted Non-Vested, beginning of period — $ — Granted 105,080 40.5 Vested — — Non-vested, end of period 105,080 $ 40.5 Aggregate intrinsic value, end of period (in millions) $ 1.6 As of December 31, 2015 , there was $3.0 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2 years . (f) Benefit Plan The Partnership sponsors a single employer 401(k) plan whereby it matches 100% of every dollar contributed up to 6% of an employee’s salary. Contributions of $7.0 million and $5.5 million were made to the plan for the years ended December 31, 2015 and 2014 , respectively.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Interest Rate Swaps The Partnership entered into interest rate swaps in April and May 2015 in connection with the issuance of the 2025 Notes in May 2015. Additionally, the Partnership entered into interest rate swaps in October and November during the year ended December 31, 2014 in connection with the issuance of the 2024 Notes and 2045 Notes in November 2014. The impact of the interest rate swaps on net income is included in other income (expense) in the Consolidated Statements of Operations as part of interest expense, net, as follows (in millions): Year Ended December 31, 2015 2014 Settlement gains on derivatives $ 3.6 $ 3.6 Commodity Swaps The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the fair value of the Partnership's derivatives are recorded in revenue in the period incurred. In addition, the Partnership's risk management policy does not allow the Partnership to take speculative positions with its derivative contracts. The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its 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 the Partnership receives a percentage of liquids as a fee for processing third-party gas or where the Partnership receives 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 its business and (3) where the Partnership is mitigating the price risk for product held in inventory or storage. The components of gain on derivative activity in the Consolidated Statements of Operations relating to commodity swaps are (in millions): Year Ended December 31, 2015 2014* Change in fair value of derivatives that are not designated for hedge accounting $ (7.7 ) $ 22.4 Settlement gain (loss) on derivative 17.1 (0.3 ) Gain on derivative activity $ 9.4 $ 22.1 ____________________________________________________________________________ * Amounts consist only of the period from March 7, 2014 through December 31, 2014. The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions): Year Ended December 31, 2015 2014 Fair value of derivative assets — current $ 16.8 $ 16.7 Fair value of derivative assets — long term — 10.0 Fair value of derivative liabilities — current (2.9 ) (3.0 ) Fair value of derivative liabilities — long term (0.1 ) (2.0 ) Net fair value of derivatives $ 13.8 $ 21.7 Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes at December 31, 2015 . The remaining term of the contracts extend no later than January 2017. December 31, 2015 Commodity Instruments Unit Volume Fair Value (In millions) NGL (short contracts) Swaps Gallons (43.9 ) $ 14.6 NGL (long contracts) Swaps Gallons 24.0 (2.8 ) Natural Gas (short contracts) Swaps MMBtu (5.5 ) 1.4 Natural Gas (long contracts) Swaps MMBtu 2.9 0.4 Condensate (short contracts) Swaps MMbbls (0.1 ) 0.2 Total fair value of derivatives $ 13.8 On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has 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 the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss as of December 31, 2015 of $16.8 million would be reduced to $13.8 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. Fair Value of Derivative Instruments Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as a gain on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions): Maturity Periods Less than one year One to two years More than two years Total fair value December 31, 2015 $ 13.9 $ (0.1 ) $ — $ 13.8

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB 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. FASB 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. The Partnership’s 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 measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2015 2014 Commodity Swaps* $ 13.8 $ 21.7 Total $ 13.8 $ 21.7 ____________________________________________________________________________ * Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date. The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820. Fair Value of Financial Instruments The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership 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 the Partnership could realize upon the sale or refinancing of such financial instruments (in millions): December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value Long-term debt $ 3,089.8 $ 2,585.5 $ 2,022.5 $ 2,026.1 Obligations under capital lease $ 16.7 $ 15.6 $ 20.3 $ 19.8 The carrying amounts of the Partnership's cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. The Partnership had $414.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of December 31, 2015 and 2014 , respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of December 31, 2015 , the Partnership had total borrowings of $ 2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1% . As of December 31, 2014 , the Partnership had total borrowings of $ 1.8 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1% . The fair value of all senior unsecured notes as of December 31, 2015 and 2014 was based on Level 2 inputs from third-party market quotations. The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies (a) Leases—Lessee The Partnership has operating leases for office space, office and field equipment. The following table summarizes the Partnership's remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions): 2016 $ 11.7 2017 9.0 2018 13.9 2019 11.0 2020 8.6 Thereafter 72.7 $ 126.9 Operating lease rental expense for the years ended December 31, 2015 , 2014 and 2013 was approximately $66.1 million , $51.4 million and zero , respectively. (b) Change of Control and Severance Agreements Certain members of management of the Partnership are parties to severance and change of control agreements with EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”). The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual 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 disclosing confidential information about the General Partner 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. (c) Environmental Issues The operation of pipelines, plants and other facilities for the gathering, processing, transmitting 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 or operator of these facilities, the Partnership 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, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. 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 the Partnership's results of operations, financial condition or cash flows. (d) Litigation Contingencies The Partnership is 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 its financial position, results of operations or cash flows. At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows. The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. 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. The Partnership's 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 have appealed the matter to the United States Court of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership owns and operates 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. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses. The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputed the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties. In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23 rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	Segment Information Identification of the majority of the Company's operating segments is based principally upon geographic regions served. The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas (“Texas”), the pipelines and processing plants located in Louisiana and NGL assets located in south 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 Ohio River Valley (“Crude and Condensate”). The Company's Crude and Condensate segment, which is identified based upon the nature of services provided to customers of the segment, has historically been referred to as the Company's ORV segment. Due to the growth in this segment, including the acquisitions of LPC and VEX, the Company has renamed this segment to more accurately reflect the assets included therein. The Company has restated the prior period to include certain crude and condensate activity in the Crude and Condensate segment. Operating activity for intersegment eliminations is shown in the corporate segment. The Company’s sales are derived from external domestic customers. Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs, investments in HEP and GCF and goodwill attributable to the Company's investment in the Partnership. The Company evaluates the performance of its operating segments based on operating revenues and segment profits. Summarized financial information concerning the Company’s reportable segments is shown in the following tables: Texas Louisiana Oklahoma Crude and Condensate Corporate Totals (In millions) Year Ended December 31, 2015: Product sales $ 320.0 $ 1,527.7 $ 5.0 $ 1,401.0 $ — $ 3,253.7 Product sales- affiliates 123.3 48.5 13.0 0.8 (66.2 ) 119.4 Midstream services 100.2 244.1 28.3 78.4 — 451.0 Midstream services- affiliates 456.7 20.0 140.7 18.0 (16.8 ) 618.6 Cost of sales (412.2 ) (1,567.6 ) (17.9 ) (1,330.6 ) 83.0 (3,245.3 ) Operating expenses (181.8 ) (105.9 ) (30.3 ) (101.9 ) — (419.9 ) Gain on derivative activity — — — — 9.4 9.4 Segment profit $ 406.2 $ 166.8 $ 138.8 $ 65.7 $ 9.4 $ 786.9 Depreciation and amortization $ (169.7 ) $ (109.1 ) $ (49.8 ) $ (51.5 ) $ (7.2 ) $ (387.3 ) Impairments $ (496.3 ) $ (787.3 ) $ (0.6 ) $ (279.2 ) $ — $ (1,563.4 ) Goodwill $ 703.5 $ — $ 190.3 $ 93.2 $ 1,426.9 $ 2,413.9 Capital expenditures $ 268.0 $ 59.2 $ 40.7 $ 187.5 $ 15.1 $ 570.5 Year Ended December 31, 2014: Product sales $ 216.5 $ 1,612.7 $ 13.1 $ 317.0 $ — $ 2,159.3 Product sales- affiliates 348.8 65.7 154.9 0.5 (64.3 ) 505.6 Midstream services 56.3 153.2 1.7 42.2 — 253.4 Midstream services- affiliates 410.8 5.8 149.1 7.5 (5.8 ) 567.4 Cost of sale (456.9 ) (1,674.2 ) (142.6 ) (290.9 ) 70.1 (2,494.5 ) Operating expenses (146.8 ) (64.9 ) (28.7 ) (43.2 ) — (283.6 ) Gain on litigation settlement — 6.1 — — — 6.1 Gain on derivative activity — — — — 22.1 22.1 Segment profit $ 428.7 $ 104.4 $ 147.5 $ 33.1 $ 22.1 $ 735.8 Depreciation and amortization $ (125.8 ) $ (69.4 ) $ (49.4 ) $ (37.0 ) $ (2.7 ) $ (284.3 ) Goodwill $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 Capital expenditures $ 271.0 $ 273.1 $ 17.1 $ 183.6 $ 13.9 $ 758.7 Year Ended December 31, 2013: Product sales $ 129.3 $ — $ 50.1 $ — $ — $ 179.4 Product sales- affiliates 1,419.8 — 696.7 — — 2,116.5 Cost of sales (1,130.4 ) — (605.9 ) — — (1,736.3 ) Operating expenses (121.2 ) — (35.0 ) — — (156.2 ) Segment profit $ 297.5 $ — $ 105.9 $ — $ — $ 403.4 Depreciation and amortization $ (110.6 ) $ — $ (76.4 ) $ — $ — $ (187.0 ) Goodwill $ 325.4 $ — $ 76.3 $ — $ — $ 401.7 Capital expenditures $ 147.0 $ — $ 66.1 $ — $ — $ 213.1 The table below represents information about segment assets as of December 31, 2015 and 2014 (in millions): Year Ended December 31, Segment Identifiable Assets: 2015 2014 Texas $ 3,709.5 $ 3,302.9 Louisiana 2,309.3 3,316.5 Oklahoma 873.4 892.8 Crude and Condensate 898.0 871.8 Corporate 1,774.9 1,822.7 Total identifiable assets $ 9,565.1 $ 10,206.7 The following table reconciles the segment profits reported above to the operating income (loss) as reported in the consolidated statements of operations (in millions): Year Ended December 31, 2015 2014 2013 Segment profits $ 786.9 $ 735.8 $ 403.4 General and administrative expenses (136.9 ) (97.3 ) (45.1 ) Depreciation and amortization (387.3 ) (284.3 ) (187.0 ) Gain (loss) on disposition of assets (1.2 ) 0.1 — Impairments (1,563.4 ) — — Operating income (loss) $ (1,301.9 ) $ 354.3 $ 171.3

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) Summarized unaudited quarterly financial data is presented below. First Second Third Fourth Total (In millions, except per unit data) 2015: Revenues $ 940.5 $ 1,274.5 $ 1,170.6 $ 1,066.5 $ 4,452.1 Impairments $ — $ — $ 799.2 $ 764.2 $ 1,563.4 Operating income (loss) $ 50.5 $ 71.4 $ (731.8 ) $ (692.0 ) $ (1,301.9 ) Net income (loss) attributable to the non-controlling interest $ 8.0 $ 28.4 $ (562.5 ) $ (528.4 ) $ (1,054.5 ) Net income (loss) attributable to EnLink Midstream, LLC $ 17.0 $ 16.2 $ (193.4 ) $ (195.0 ) $ (355.2 ) Net income (loss) per common unit-basic $ 0.10 $ 0.09 $ (1.18 ) $ (1.18 ) $ (2.17 ) Net income (loss) per common unit-diluted $ 0.10 $ 0.09 $ (1.18 ) $ (1.18 ) $ (2.17 ) 2014: Revenues $ 723.0 $ 927.2 $ 857.4 $ 1,000.2 $ 3,507.8 Operating income $ 73.1 $ 89.8 $ 87.0 $ 104.4 354.3 Net income attributable to the non-controlling interest $ 7.1 $ 35.7 $ 37.7 $ 46.2 $ 126.7 Net income attributable to EnLink Midstream, LLC $ 41.4 $ 26.7 $ 26.5 $ 29.4 $ 124.0 Net income per limited partner unit-basic $ 0.04 $ 0.18 $ 0.18 $ 0.16 $ 0.55 Net income per limited partner unit-diluted $ 0.04 $ 0.18 $ 0.17 $ 0.16 $ 0.55

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations. The following schedule summarizes net income from discontinued operations (in millions): Year Ended December 31, 2014 2013 Revenues: Revenues $ 6.8 $ 42.1 Revenues - affiliates 10.5 84.6 Total revenues 17.3 126.7 Operating costs and expenses: Operating expenses 15.7 130.3 Total operating costs expenses 15.7 130.3 Income (loss) before income taxes 1.6 (3.6 ) Income tax provision (benefit) 0.6 (1.3 ) Net income (loss) 1.0 (2.3 ) Net income attributable to non-controlling interest — (1.3 ) Net income (loss) including non-controlling interest $ 1.0 $ (3.6 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following schedule summarizes the Partnership's non-cash financing activities for the period presented. December 31, 2015 (In millions) Non-cash financing activities: Non-cash issuance of common units (1) $ 180.0 Non-cash issuance of Class C Common Units (1) $ 180.0 ____________________________________________________________________________ (1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion. Also, see Note 5 - Affiliate Transactions for non-cash activities related to Predecessor operations with Devon prior to March 7, 2014.

Other Information

Other Information	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other Information	Other Information The following tables present additional detail for certain balance sheet captions. Other Current Liabilities Other current liabilities consisted of the following: Year Ended December 31, 2015 2014 (in millions) Accrued interest $ 23.2 $ 16.9 Accrued wages and benefits, including taxes 27.7 19.7 Accrued ad valorem taxes 27.0 23.2 Capital expenditure accruals 22.3 22.6 Onerous performance obligation 17.0 20.3 Other 57.6 49.6 Other current liabilities $ 174.8 $ 152.3

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Event [Line Items]
Subsequent Events	(21) Subsequent Events Tall Oak Acquisition. On January 7, 2016, the Partnership and ENLC acquired an 84% and 16% interest, respectively, in subsidiaries of Tall Oak Midstream, LLC for $1.55 billion , subject to certain adjustments. The first installment of $1.05 billion for the acquisition was paid at closing and the final installment of $500.0 million is due no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The first installment consisted of approximately $1.05 billion and was funded by (a) approximately $788.0 million in cash contributed by the Partnership, a portion of which was derived from the proceeds from the issuance of the Preferred Units (as defined below), and (b) (i) 15,564,009 of our common units issued directly by us and (ii) approximately $19.5 million in cash contributed by us. The Tall Oak assets serve gathering and processing needs in the STACK and Central Northern Oklahoma Woodford (“CNOW”) plays in Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that have a remaining weighted-average term of approximately 15 years . The assets include two gathering and processing systems and will include a rich gas pipeline currently under construction that will connect the two systems. Due to the timing of the acquisition, the Partnership has not yet completed its initial accounting analysis. Issuance of Preferred Units. On January 7, 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units representing limited partner interests in the Partnership to Enfield Holdings, L.P. in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $725.3 million after fees and deductions. Proceeds from the Private Placement will be used to partially fund the Partnership’s portion of the purchase price payable in connection with the Tall Oak Acquisition.

Significant Accounting Polici29

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	(a) Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Further, the consolidated financial statements give effect to the business combination and related transactions discussed above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of ENLC after the business combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC's non-controlling interests in the Partnership, were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired was recorded as goodwill. Financial results on and subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and EMI, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. All significant intercompany transactions and balances have been eliminated. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non-contributed assets have been presented as discontinued operations. In conjunction with the business combination, Midstream Holdings became a non-taxable entity which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity. On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to “Devon investment interest in net income” on the Company's Consolidated Statements of Operations.
Management's Use of Estimates	(b) Management's Use of Estimates The preparation of financial statements in accordance with US GAAP requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.
Revenue Recognition	(c) Revenue Recognition The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization and brine services, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the Consolidated Statements of Operations as follows: • Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above. • Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above. The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).
Gas Imbalance Accounting	(d) Gas Imbalance Accounting Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Company had imbalance payables of $2.6 million and $1.5 million at December 31, 2015 and 2014 , respectively, which approximate the fair value of these imbalances. The Company had imbalance receivables of $3.6 million and $1.2 million at December 31, 2015 and 2014 , respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued Revenue and other” and “Accrued gas, condensate and crude oil purchases”, respectively, on the Consolidated Balance Sheets.
Cash and Cash Equivalents	(e) Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory	(f) Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory The Partnership's inventories of products consist of natural gas, NGLs, crude oil and condensate. The Partnership reports these assets at the lower of cost or market value which is determined by using the first-in, first-out method.
Property, Plant, and Equipment	(g) Property, Plant, and Equipment Property, plant and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value, including the Partnership's assets acquired by the Predecessor in the business combination. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Subsequent to the business combination, interest costs for material projects are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use. The components of property, plant and equipment are as follows (in millions): Year Ended December 31, 2015 2014 Transmission assets $ 1,285.1 $ 1,100.1 Gathering systems 2,999.2 2,391.9 Gas processing plants 2,673.7 2,356.1 Other property and equipment 135.9 379.5 Construction in process 330.5 241.5 Property, plant and equipment 7,424.4 6,469.1 Accumulated depreciation (1,757.6 ) (1,426.3 ) Property, plant and equipment, net $ 5,666.8 $ 5,042.8 Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, the Company is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Company changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Company’s legacy assets. In accordance with FASB ASC 250, the Company determined that the change in depreciation method was a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method was applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense for the year ended December 31, 2014 by approximately $29.4 million and $0.18 per unit. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years Depreciation expense of $331.3 million , $247.8 million and $187.0 million was recorded for the years ended December 31, 2015 , 2014 and 2013 , respectively. Gain or Loss on Disposition. Upon the disposition or retirement of property, plant and equipment related to continuing operations, any gain or loss is recognized in operating income in the statement of operations. When a disposition or retirement occurs which qualifies as discontinued operations, any gain or loss is recognized as income or loss from discontinued operations in the statement of operations. We recognized a loss on disposition of assets of $1.2 million for the year ended December 31, 2015 , which primarily relates to the retirement of a compressor due to fire damage. For the year ended December 31, 2015 , we retired net property, plant and equipment of $5.1 million , which was offset by $2.9 million of nonrefundable cash proceeds collected from our insurance carrier and $1.0 million of proceeds from the sale of property. Additionally, we collected $2.4 million of business interruption proceeds from our insurance carrier which was presented in the Midstream services revenue line item in the Consolidated Statement of Operations as of December 31, 2015 . Impairment Review. We evaluate our property, plant 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. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. Our estimate of cash flows is based on assumptions which include (1) the amount of fee based services, the purchase and resale margins and the volume of natural gas, NGL, condensate and crude oil available to the asset, (2) markets available to the asset, (3) operating expenses, and (4) future natural gas, crude oil, condensate and NGL product prices. The volume of available natural gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. During December 2015, the Partnership recognized a $12.1 million impairment on property, plant and equipment, primarily related to costs associated with the cancellation of various capital projects in its Texas, Louisiana and Crude and Condensate segments.
Equity Method of Accounting	(h) Equity Method of Accounting The Company accounts for investments where it does not control the investment but has the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by the Company’s proportionate share of the investee’s net income and by contributions made, and decreased by the Predecessor’s proportionate share of the investee’s net losses and by distributions received. The Company evaluates its unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable.
Goodwill	(i) Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company evaluates goodwill for impairment annually as of October 31 st , 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. The Company first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. Company may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During the third and fourth quarters of 2015, the Company determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in its unit price caused a change in circumstances warranting an interim impairment test. Based on these triggering events, the Company performed a goodwill impairment analysis on all reporting units. Through the analysis, a goodwill impairment loss for the Company's Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015, which is included in impairment expense in the Consolidated Statements of Operations. See Note 4- Goodwill and Intangible Assets for further discussion regarding the goodwill impairment.
Intangible Assets	(j) 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.
Asset Retirement Obligations	(k) Asset Retirement Obligations The Company recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Company’s retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight line depreciation method similar to that used for the associated property, plant and equipment.
Other Long-Term Liabilities	(l) Other Long-Term Liabilities Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the business combination of $62.8 million and $80.7 million for the years ended December 31, 2015 and 2014 , respectively. The Company has one delivery contract which requires it to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Company realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchase gas costs.
Derivatives	(m) Derivatives The Company uses derivative instruments to hedge against changes in cash flows related to product price only. We generally determine the fair value of swap contracts based on the difference between the derivative's fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities in accordance with FASB ASC 815. Changes in fair value of derivative instruments are recorded in gain (loss) on derivative activity in the period of change. Realized gains and losses on commodity related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statement of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities.
Concentrations of Credit Risk	(n) Concentrations of Credit Risk Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than the Company's exposure to Devon discussed below, since the Company's customers represent a broad and diverse group of energy marketers and end users. In addition, the Company continually monitors and reviews credit exposure of its marketing counter-parties and letters of credit or other appropriate security are obtained when considered necessary to limit the risk of loss. The Company records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Company had a reserve for uncollectible receivables as of December 31, 2015 of $0.3 million and had no reserve for uncollectible receivables as of December 31, 2014 . During the year ended December 31, 2015 and 2014 , the Company had only one customer other than the affiliate transactions that individually represented greater than 10.0% of its consolidated midstream revenues. The customer is located in the Louisiana segment and represented 11.7% and 11.0% , of the consolidated revenues for the year ended December 31, 2015 and 2014 , respectively. The affiliate transactions with Devon represented 16.6% , 30.6% and 92.2% of the consolidated midstream revenues for the years ended December 31, 2015 , 2014 and 2013 , respectively. As the Company continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. Devon and the Company's Louisiana customer represent a significant percentage of revenues and the loss of either customer would have a material adverse impact on the Company's results of operations because the gross operating margin received from transactions with these customers is material to the Company.
Environmental Costs	(o) Environmental Costs Environmental expenditures are expensed or capitalized as depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated.
Unit-Based Awards	(p) Unit-Based Awards Prior to the business combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon's U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods. The Company recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with FASB ASC 718. The Company and the Partnership each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC's unit-based compensation plans awarded to directors, officers and employees of the general partner of the Partnership are recorded by the Partnership since the Company has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings.
Commitments and Contingencies	(q) Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Discontinued Operations	(r) Discontinued Operations The Company classifies as discontinued operations its assets that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Company also includes as discontinued operations Predecessor assets that were not contributed in the business combination.
Other Assets	(s) Other Assets Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $23.8 million and $17.5 million as of December 31, 2015 and 2014, respectively, are included in other assets, net. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the debt.
Legal Costs Expected to be Incurred in Connection with a Loss Contingency	(t) Legal Costs Expected to be Incurred in Connection with a Loss Contingency Legal costs incurred in connection with a loss contingency are expensed as incurred.
Redeemable Non-controlling Interest	(u) Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder's share of net income or loss and distributions).
Recent Accounting Pronouncements	(v) Recent Accounting Pronouncements In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). Under this new standard, the FASB issued new guidance related to accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. ASU 2016-01 is effective beginning after December 15, 2017 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). The new standard requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective in fiscal years beginning after December 15, 2016, including interim periods within those years. Early adoption is permitted. ASU 2015-17 may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively. We are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures. In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”) which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the standard will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and will have no impact on our consolidated financial statements but will require to provide additional disclosure to our footnotes. Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the year ended December 31, 2015, and have determined that none would have a material impact on our Consolidated Financial Statements.

Significant Accounting Polici30

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Property, Plant, and Equipment	The components of property, plant and equipment are as follows (in millions): Year Ended December 31, 2015 2014 Transmission assets $ 1,285.1 $ 1,100.1 Gathering systems 2,999.2 2,391.9 Gas processing plants 2,673.7 2,356.1 Other property and equipment 135.9 379.5 Construction in process 330.5 241.5 Property, plant and equipment 7,424.4 6,469.1 Accumulated depreciation (1,757.6 ) (1,426.3 ) Property, plant and equipment, net $ 5,666.8 $ 5,042.8
Schedule Of Property, Plant, and Equipment Useful Lives	Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Gas processing plants 20 - 25 years Other property and equipment 3 - 15 years

Acquisitions (Table)

Acquisitions (Table)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Schedule of Prior Period Adjustments Related to Asset Drop Down	The following tables present the impact of the VEX Drop Down as presented in the Company's historical Consolidated Statements of Operations for the years ended December 31, 2015 and 2014 . Year Ended December 31, 2015 Company Historical VEX Combined (in millions) Revenues $ 4,446.8 $ 5.3 $ 4,452.1 Net income (loss) $ (1,411.5 ) $ 1.8 $ (1,409.7 ) Net loss attributable to non-controlling interest $ (1,054.5 ) $ — $ (1,054.5 ) Net income (loss) attributable to EnLink Midstream, LLC $ (357.0 ) $ 1.8 $ (355.2 ) EnLink Midstream, LLC interest in net loss $ (357.0 ) $ — $ (357.0 )	Year Ended December 31, 2014 Company Historical VEX** Combined (in millions) Revenues $ 3,500.4 $ 7.4 $ 3,507.8 Net income (loss) $ 252.7 $ (2.0 ) $ 250.7 Net income attributable to non-controlling interest $ 126.7 $ — $ 126.7 Net income (loss) attributable to EnLink Midstream, LLC $ 126.0 $ (2.0 ) $ 124.0 EnLink Midstream, LLC interest in net income $ 90.5 $ — $ 90.5 ____________________________________________________________________________ ** The VEX amounts reflect the period from February 28, 2014 (the date VEX was acquired by Devon) through December 31, 2014.
Business Acquisition, Pro Forma Information	Pro forma financial information associated with the business combination and acquisitions is reflected below. Year Ended December 31, 2015 2014 (in millions except for per unit data) Pro forma total revenues (1) $ 4,585.5 $ 5,679.3 Pro forma net income (loss) $ (1,413.0 ) $ 220.2 Pro forma net income (loss) attributable to Enlink Midstream, LLC $ (355.5 ) $ 64.8 Pro forma net income (loss) per common unit: Basic $ (2.18 ) $ 0.41 Diluted $ (2.18 ) $ 0.41 ____________________________________________________________________________ (1) On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.
Chevron Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Property, plant and equipment $ 225.3 Intangibles 13.0 Liabilities assumed: Current liabilities (6.8 ) Total purchase price $ 231.5
LPC [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Current assets (including $21.1 million in cash) $ 107.4 Property, plant and equipment 29.8 Intangibles 43.2 Goodwill 29.6 Liabilities assumed: Current liabilities (97.9 ) Deferred tax liability (4.0 ) Total identifiable net assets $ 108.1
Coronado [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. Purchase Price Allocation (in millions): Assets acquired: Current assets (including $1.4 million in cash) $ 20.8 Property, plant and equipment 302.1 Intangibles 281.0 Goodwill 18.7 Liabilities assumed: Current liabilities (22.3 ) Total identifiable net assets $ 600.3
Matador [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. Purchase Price Allocation (in millions): Assets acquired: Current assets $ 1.9 Property, plant and equipment 35.5 Intangibles 98.8 Goodwill 9.1 Total identifiable net assets $ 145.3

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill [Line Items]
Schedule of Goodwill	The table below provides a summary of the Partnership’s change in carrying amount of goodwill, by assigned reporting unit. Texas Louisiana Oklahoma Crude and Condensate Corporate Totals (in millions) Year Ended December 31, 2015 Balance, beginning of period $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 Acquisitions (1) 27.8 — — 29.6 — 57.4 Impairment (492.5 ) (786.8 ) — (48.9 ) — (1,328.2 ) Balance, end of period $ 703.5 $ — $ 190.3 $ 93.2 $ 1,426.9 $ 2,413.9 Year Ended December 31, 2014 Balance, beginning of period $ 325.4 $ — $ 76.3 $ — $ — $ 401.7 Acquisitions (1) 842.8 786.8 114.0 112.5 1,426.9 3,283.0 Balance, end of period $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 ____________________________________________________________________________ (1) See Note 3-Acquisitions for further discussion.
Schedule of Finite-Lived Intangible Assets	The following table represents the Partnership's change in carrying value of intangible assets for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2015 Customer relationships, beginning of period $ 569.5 $ (36.5 ) $ 533.0 Acquisitions 436.0 — 436.0 Amortization expense — (56.0 ) (56.0 ) Impairment (261.0 ) 37.9 (223.1 ) Customer relationships, end of period $ 744.5 $ (54.6 ) $ 689.9 Year Ended December 31, 2014 Customer relationships, beginning of period $ — $ — $ — Acquisitions 569.5 — 569.5 Amortization expense — (36.5 ) (36.5 ) Customer relationships, end of period $ 569.5 $ (36.5 ) $ 533.0
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions): 2016 $ 46.1 2017 46.1 2018 46.1 2019 46.1 2020 46.1 Thereafter 459.4 Total $ 689.9

Affiliate Transactions (Tables)

Affiliate Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Affiliate Transactions	The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions): Year Ended December 31, 2014 2013 Continuing Operations: Operating revenues - affiliates $ (436.4 ) $ (2,116.5 ) Operating expenses - affiliates 340.0 1,669.5 Net affiliate transactions (96.4 ) (447.0 ) Capital expenditures 16.2 244.3 Other third-party transactions, net 58.9 51.5 Net third-party transactions 75.1 295.8 Net cash distributions to Devon - continuing operations (21.3 ) (151.2 ) Non-cash distribution of net assets to Devon (6.3 ) — Total net distributions per equity $ (27.6 ) $ (151.2 ) Discontinued operations: Operating revenues - affiliates $ (10.4 ) $ (84.6 ) Operating expenses - affiliates 5.0 32.7 Cash used in financing activities - affiliates — (5.6 ) Net affiliate transactions (5.4 ) (57.5 ) Capital expenditures 0.6 1.1 Other third-party transactions, net 0.4 (72.0 ) Net third-party transactions 1.0 (70.9 ) Net distributions to Devon and non-controlling interests - discontinued operations (4.4 ) (128.4 ) Non-cash distribution of net assets to Devon (39.9 ) — Total net distributions per equity $ (44.3 ) $ (128.4 ) Total distributions- continuing and discontinued operations (1) $ (71.9 ) $ (279.6 ) ____________________________________________________________________________ (1) Total distributions- continuing and discontinued operations for the year ended December 31, 2013 of $279.6 million does not include $5.5 million of distributions related to certain assets that weren't transferred to the Partnership, which are included in the Distribution to Predecessor line item on the Consolidated Statements of Changes in Members' Equity.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Indebtedness Table	As of December 31, 2015 and 2014 , long-term debt consisted of the following (in millions): Year Ended December 31, 2015 2014 Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at December 31, 2015 and December 31, 2014 was 1.8% and 1.9%, respectively $ 414.0 $ 237.0 Credit facility (due 2019) — — The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at December 31, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70% 399.6 399.5 The Partnership's senior unsecured notes (due 2022), including a premium of $18.9 million at December 31, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125% 181.4 184.4 The Partnership's senior unsecured notes (due 2024), net of premium of $2.9 million at December 31, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40% 552.9 553.2 The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at December 31, 2015, which bear interest at the rate of 4.15% 748.8 — The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at December 31, 2015 and $0.3 million at December 31, 2014, which bear interest at the rate of 5.60% 349.8 349.7 The Partnership's senior unsecured notes (due 2045), net of discount of $6.9 million at December 31, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05% 443.1 298.3 Other debt 0.2 0.4 Debt classified as long-term $ 3,089.8 $ 2,022.5
Schedule of Maturities of Long-term Debt	Maturities. Maturities for the long-term debt as of December 31, 2015 are as follows (in millions): 2016 $ 0.1 2017 0.1 2018 — 2019 400.0 2020 414.0 Thereafter 2,262.5 Subtotal 3,076.7 Add: net premium 13.1 Total outstanding debt $ 3,089.8
Schedule of Debt Leverage	Pricing Level Debt Ratings Applicable Rate Commitment Fee EuroDollar Rate/Letter of Credit Base Rate + 1 A-/A3 or better 0.100% 1.000% —% 2 BBB+/Baa1 0.125% 1.125% 0.125% 3 BBB/Baa2 0.175% 1.250% 0.250% 4 BBB-/Baa3 0.225% 1.500% 0.500% 5 BB+/Ba1 0.275% 1.625% 0.625% 6 BB/Ba2 or worse 0.350% 1.750% 0.750%

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The provision for income taxes is comprised of the following (in millions): Year Ended December 31, 2015 2014 2013 Current tax expense $ 3.1 $ 9.0 $ 31.5 Deferred tax expense 22.6 67.4 35.5 Total income tax expense $ 25.7 $ 76.4 $ 67.0 The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows: Year Ended December 31, 2015 2014 2013 Expected income tax expense (benefit) based on federal statutory rate of 35% $ (116.0 ) $ 70.7 $ 65.1 State income taxes, net of federal benefit and other (7.7 ) 5.7 1.9 Goodwill impairment 149.4 — — Total income tax expense $ 25.7 $ 76.4 $ 67.0
Schedule of Deferred Tax Assets and Liabilities	Our deferred income tax assets and liabilities as of December 31, 2015 and 2014 are as follows: Year Ended December 31, 2015 2014 Deferred income tax assets: Federal net operating loss carryforward, current $ — $ 16.9 Total current deferred tax assets — 16.9 Asset retirement obligations and other 2.3 2.0 State net operating loss carryforward, non current 3.6 4.2 Federal net operating loss carryforward, non current 20.9 — Total non current deferred tax assets 26.8 6.2 Total deferred tax assets 26.8 23.1 Deferred tax liabilities: Property, plant, equipment, and intangible assets, non current (557.6 ) (523.5 ) Other (1.3 ) (9.3 ) Total non current deferred tax liabilities (558.9 ) (532.8 ) Deferred tax liability, net $ (532.1 ) $ (509.7 )
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of the beginning and ending amount of the unrecognized tax benefits is as follows (in millions): Year Ended December 31, 2015 2014 Balance at January 1 $ 2.0 $ — Unrecognized tax positions assumed in merger — 3.8 Decrease due to prior year tax positions (0.5 ) (2.0 ) Increases due to current year tax positions — 0.2 Balance at December 31 $ 1.5 $ 2.0

Certain Provisions of the Par36

Certain Provisions of the Partnership Agreement (Tables)	12 Months Ended
	Dec. 31, 2015
Partners' Capital [Abstract]
Distributions Made to Limited Partner, by Distribution	A summary of the Partnership's distribution activity relating to the common units for the years ended December 31, 2015 and 2014 is provided below: Declaration period Distribution/unit Date paid/payable 2015 First Quarter of 2015 (1) $ 0.380 May 14, 2015 Second Quarter of 2015 (2) $ 0.385 August 13, 2015 Third Quarter of 2015 $ 0.390 November 12, 2015 Fourth Quarter of 2015 $ 0.390 February 11, 2016 2014 First Quarter of 2014 (3) $ 0.360 May 14, 2014 Second Quarter of 2014 $ 0.365 August 13, 2014 Third Quarter of 2014 $ 0.370 November 13, 2014 Fourth Quarter of 2014 $ 0.375 February 12, 2015 ____________________________________________________________________________ (1) The Partnership's partial first quarter 2015 distributions on its Class D Common Units of $0.18 per unit were paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015. (2) The Partnership's partial second quarter 2015 distributions on its Class E Common Units of $0.15 per unit were paid on August 13, 2015. Distributions paid for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015. (3) The Partnership's first quarter 2014 distributions on its Class B Common Units of $0.10 per unit were paid on May 14, 2014. Distributions declared for the Class B Common Units represent a pro rata distribution for the number of days the Class B Common Units were issued and outstanding during the quarter. The Class B Common Units automatically converted into common units on a one-for-one basis on May 6, 2014.
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution	The net income allocated to the General Partner is as follows (in millions): Year Ended December 31, 2015 2014 Income allocation for incentive distributions $ 47.5 $ 20.6 Unit-based compensation attributable to ENLC’s restricted units (18.3 ) (10.4 ) General Partner share of net income (loss) (6.7 ) 1.1 General Partner interest in drop down transactions 35.5 127.0 General Partner interest in net income (loss) $ 58.0 $ 138.3

Earnings per Unit and Dilutio37

Earnings per Unit and Dilution Computations (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions except per unit amounts): Year Ended December 31, 2015 2014* Net income attributable to Enlink Midstream, LLC $ (357.0 ) $ 90.5 Distributed earnings allocated to: Common units (1) (2) $ 165.0 $ 126.8 Unvested restricted units (1) 1.1 0.8 Total distributed earnings $ 166.1 $ 127.6 Undistributed loss allocated to: Common units (2) $ (519.5 ) $ (36.9 ) Unvested restricted units (3.6 ) (0.2 ) Total undistributed loss $ (523.1 ) $ (37.1 ) Net income (loss) allocated to: Common units (2) $ (354.5 ) $ 89.9 Unvested restricted units (2.5 ) 0.6 Total net income (loss) $ (357.0 ) $ 90.5 Total basic and diluted net income (loss) per unit: Basic $ (2.17 ) $ 0.55 Diluted $ (2.17 ) 0.55 ____________________________________________________________________________ * The 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014. (1) The December 31, 2015 and 2014 amount represents a declared distribution of $0.255 per unit payable February 12, 2016 , and distributions paid of $0.245 per unit on May 15, 2015, $0.25 per unit on August 14, 2015, $0.255 per unit on November 13, 2015, $0.18 per unit on May 15, 2014, $0.22 per unit on August 13, 2014, $0.23 per unit on November 14, 2014, and $0.235 per unit on on February 13, 2015. (2) The 2014 amount includes distribution of $0.05 per unit for Class B Units paid on May 15, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014.
Schedule of Weighted Average Number of Shares	The following are the unit amounts used to compute the basic and diluted earnings per unit for the years ended December 31, 2015 and 2014 (in millions): Year Ended December 31, 2015 2014 Basic weighted average units outstanding: Weighted average common units outstanding 164.2 164.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 164.2 164.0 Dilutive effect of restricted incentive units issued — 0.3 Total weighted average diluted common units outstanding 164.2 164.3

Asset Retirement Obligations (T

Asset Retirement Obligations (Table)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligations	The schedule below summarizes the changes in the Partnership’s asset retirement obligations: Year Ended December 31, 2015 2014 (in millions) Beginning asset retirement obligation $ 20.6 $ 7.7 Revisions to existing liabilities (4.0 ) 2.2 Liabilities acquired — 10.2 Accretion 0.6 0.5 Liabilities settled (3.2 ) — Ending asset retirement obligation $ 14.0 $ 20.6

Investment in Unconsolidated 39

Investment in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): Gulf Coast Fractionators Howard Energy Partners (1) Total December 31, 2015 Contributions $ — $ 25.8 $ 25.8 Distributions $ 14.5 $ 28.2 $ 42.7 Equity in income $ 13.0 $ 7.4 $ 20.4 December 31, 2014 (1) Contributions $ — $ 5.7 $ 5.7 Distributions $ 11.0 $ 12.7 $ 23.7 Equity in income $ 17.1 $ 1.8 $ 18.9 December 31, 2013 Distributions $ 12.0 $ — $ 12.0 Equity in income $ 14.8 $ — $ 14.8 ____________________________________________________________________________ (1) Includes income, distributions, and contributions for the period from March 7, 2014 through December 31, 2014. The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2015 2014 Gulf Coast Fractionators (1) $ 52.6 $ 54.1 Howard Energy Partners 221.7 216.7 Total investments in unconsolidated affiliates $ 274.3 $ 270.8 ____________________________________________________________________________ (1) Devon retained $13.1 million of the undistributed earnings due from GCF, as of March 7, 2014 when the GCF contractual right allocating the benefits and burdens of the 38.75% ownership interest in GCF to the Partnership became effective. The $13.1 million of the undistributed earnings was reflected as a reduction in the GCF investment on March 7, 2014.

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share Based Payment Award Other Than Stock Options Valuation Assumption	The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions. EnLink Midstream, LLC Performance Units: 2015 Beginning TSR Price $ 34.24 Risk-free interest rate 0.99 % Volatility factor 33.02 % Distribution yield 2.98 % The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions. EnLink Midstream Partners, LP Performance Units: 2015 Beginning TSR Price $ 27.68 Risk-free interest rate 0.99 % Volatility factor 33.01 % Distribution yield 5.66 %
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions): Year Ended December 31, 2015 2014 2013 Cost of unit-based compensation allocated to Predecessor general and $ — $ 2.8 $ 12.8 Cost of unit-based compensation charged to general and administrative expense 31.1 16.9 — Cost of unit-based compensation charged to operating expense 5.0 2.7 — Total amount charged to income $ 36.1 $ 22.4 $ 12.8 Interest of non-controlling partners in unit-based compensation $ 14.0 $ 8.3 $ — Amount of related income tax expense recognized in income $ 8.3 $ 5.3 $ 4.8 ____________________________________________________________________________ (1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity.
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	A summary of the restricted incentive unit activities for the year ended December 31, 2015 is provided below: EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 986,472 $ 37.03 Granted 508,101 31.12 Vested* (273,791 ) 35.87 Forfeited (71,889 ) 35.55 Non-vested, end of period 1,148,893 $ 34.78 Aggregate intrinsic value, end of period (in millions) $ 17.3 ____________________________________________________________________________ * Vested units include 86,635 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive unit activity for the year ended December 31, 2015 is provided below: EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,022,191 $ 31.25 Granted 596,508 26.50 Vested* (281,319 ) 28.79 Forfeited (83,651 ) 30.55 Non-vested, end of period 1,253,729 $ 29.59 Aggregate intrinsic value, end of period (in millions) $ 20.8 ____________________________________________________________________________ * Vested units include 95,127 units withheld for payroll taxes paid on behalf of employees.
Schedule of Share Based Compensation Restricted Stock and Restricted Stock Units Vested and Fair Value Vested	A summary of the restricted incentive units' aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2015 and 2014 are provided below (in millions): Year Ended December 31, EnLink Midstream Partners, LP Restricted Incentive Units: 2015 2014 Aggregate intrinsic value of units vested $ 7.5 $ 1.8 Fair value of units vested $ 8.1 $ 1.9 A summary of the restricted units' aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2015 and 2014 are provided below (in millions): Year Ended December 31, EnLink Midstream LLC Restricted Incentive Units: 2015 2014 Aggregate intrinsic value of units vested $ 9.2 $ 3.1 Fair value of units vested $ 9.8 $ 2.9
Schedule of Nonvested Performance-based Units Activity	The following table presents a summary of the Partnership's performance units. Year Ended EnLink Midstream Partners, LP Performance Units: Number of Weighted Non-Vested, beginning of period — $ — Granted 118,126 35.41 Vested — — Non-vested, end of period 118,126 $ 35.41 Aggregate intrinsic value, end of period (in millions) $ 2.0 The following table presents a summary of the Company's performance units. Year Ended EnLink Midstream, LLC Performance Units: Number of Weighted Non-Vested, beginning of period — $ — Granted 105,080 40.5 Vested — — Non-vested, end of period 105,080 $ 40.5 Aggregate intrinsic value, end of period (in millions) $ 1.6

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Interest Rate Derivatives	The impact of the interest rate swaps on net income is included in other income (expense) in the Consolidated Statements of Operations as part of interest expense, net, as follows (in millions): Year Ended December 31, 2015 2014 Settlement gains on derivatives $ 3.6 $ 3.6
Commodity Swap	The components of gain on derivative activity in the Consolidated Statements of Operations relating to commodity swaps are (in millions): Year Ended December 31, 2015 2014* Change in fair value of derivatives that are not designated for hedge accounting $ (7.7 ) $ 22.4 Settlement gain (loss) on derivative 17.1 (0.3 ) Gain on derivative activity $ 9.4 $ 22.1 ____________________________________________________________________________ * Amounts consist only of the period from March 7, 2014 through December 31, 2014.
Fair Value of Derivative Assets and Liabilities relating to commodity swaps	The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions): Year Ended December 31, 2015 2014 Fair value of derivative assets — current $ 16.8 $ 16.7 Fair value of derivative assets — long term — 10.0 Fair value of derivative liabilities — current (2.9 ) (3.0 ) Fair value of derivative liabilities — long term (0.1 ) (2.0 ) Net fair value of derivatives $ 13.8 $ 21.7
Notional Amount and Fair Value of Derivative Instruments	Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes at December 31, 2015 . The remaining term of the contracts extend no later than January 2017. December 31, 2015 Commodity Instruments Unit Volume Fair Value (In millions) NGL (short contracts) Swaps Gallons (43.9 ) $ 14.6 NGL (long contracts) Swaps Gallons 24.0 (2.8 ) Natural Gas (short contracts) Swaps MMBtu (5.5 ) 1.4 Natural Gas (long contracts) Swaps MMBtu 2.9 0.4 Condensate (short contracts) Swaps MMbbls (0.1 ) 0.2 Total fair value of derivatives $ 13.8
Derivatives Other than Cash Flow Hedges	The estimated fair value of derivative contracts by maturity date was as follows (in millions): Maturity Periods Less than one year One to two years More than two years Total fair value December 31, 2015 $ 13.9 $ (0.1 ) $ — $ 13.8

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Derivative Instrument	Net assets measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2015 2014 Commodity Swaps* $ 13.8 $ 21.7 Total $ 13.8 $ 21.7 ____________________________________________________________________________ * Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date. The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
Fair Value Financial Instrument	Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions): December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value Long-term debt $ 3,089.8 $ 2,585.5 $ 2,022.5 $ 2,026.1 Obligations under capital lease $ 16.7 $ 15.6 $ 20.3 $ 19.8

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The following table summarizes the Partnership's remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions): 2016 $ 11.7 2017 9.0 2018 13.9 2019 11.0 2020 8.6 Thereafter 72.7 $ 126.9

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Company Reportable Segement	Summarized financial information concerning the Company’s reportable segments is shown in the following tables: Texas Louisiana Oklahoma Crude and Condensate Corporate Totals (In millions) Year Ended December 31, 2015: Product sales $ 320.0 $ 1,527.7 $ 5.0 $ 1,401.0 $ — $ 3,253.7 Product sales- affiliates 123.3 48.5 13.0 0.8 (66.2 ) 119.4 Midstream services 100.2 244.1 28.3 78.4 — 451.0 Midstream services- affiliates 456.7 20.0 140.7 18.0 (16.8 ) 618.6 Cost of sales (412.2 ) (1,567.6 ) (17.9 ) (1,330.6 ) 83.0 (3,245.3 ) Operating expenses (181.8 ) (105.9 ) (30.3 ) (101.9 ) — (419.9 ) Gain on derivative activity — — — — 9.4 9.4 Segment profit $ 406.2 $ 166.8 $ 138.8 $ 65.7 $ 9.4 $ 786.9 Depreciation and amortization $ (169.7 ) $ (109.1 ) $ (49.8 ) $ (51.5 ) $ (7.2 ) $ (387.3 ) Impairments $ (496.3 ) $ (787.3 ) $ (0.6 ) $ (279.2 ) $ — $ (1,563.4 ) Goodwill $ 703.5 $ — $ 190.3 $ 93.2 $ 1,426.9 $ 2,413.9 Capital expenditures $ 268.0 $ 59.2 $ 40.7 $ 187.5 $ 15.1 $ 570.5 Year Ended December 31, 2014: Product sales $ 216.5 $ 1,612.7 $ 13.1 $ 317.0 $ — $ 2,159.3 Product sales- affiliates 348.8 65.7 154.9 0.5 (64.3 ) 505.6 Midstream services 56.3 153.2 1.7 42.2 — 253.4 Midstream services- affiliates 410.8 5.8 149.1 7.5 (5.8 ) 567.4 Cost of sale (456.9 ) (1,674.2 ) (142.6 ) (290.9 ) 70.1 (2,494.5 ) Operating expenses (146.8 ) (64.9 ) (28.7 ) (43.2 ) — (283.6 ) Gain on litigation settlement — 6.1 — — — 6.1 Gain on derivative activity — — — — 22.1 22.1 Segment profit $ 428.7 $ 104.4 $ 147.5 $ 33.1 $ 22.1 $ 735.8 Depreciation and amortization $ (125.8 ) $ (69.4 ) $ (49.4 ) $ (37.0 ) $ (2.7 ) $ (284.3 ) Goodwill $ 1,168.2 $ 786.8 $ 190.3 $ 112.5 $ 1,426.9 $ 3,684.7 Capital expenditures $ 271.0 $ 273.1 $ 17.1 $ 183.6 $ 13.9 $ 758.7 Year Ended December 31, 2013: Product sales $ 129.3 $ — $ 50.1 $ — $ — $ 179.4 Product sales- affiliates 1,419.8 — 696.7 — — 2,116.5 Cost of sales (1,130.4 ) — (605.9 ) — — (1,736.3 ) Operating expenses (121.2 ) — (35.0 ) — — (156.2 ) Segment profit $ 297.5 $ — $ 105.9 $ — $ — $ 403.4 Depreciation and amortization $ (110.6 ) $ — $ (76.4 ) $ — $ — $ (187.0 ) Goodwill $ 325.4 $ — $ 76.3 $ — $ — $ 401.7 Capital expenditures $ 147.0 $ — $ 66.1 $ — $ — $ 213.1
Segment Table reconciliation to Condensed Consolidated Financial Statement	The following table reconciles the segment profits reported above to the operating income (loss) as reported in the consolidated statements of operations (in millions): Year Ended December 31, 2015 2014 2013 Segment profits $ 786.9 $ 735.8 $ 403.4 General and administrative expenses (136.9 ) (97.3 ) (45.1 ) Depreciation and amortization (387.3 ) (284.3 ) (187.0 ) Gain (loss) on disposition of assets (1.2 ) 0.1 — Impairments (1,563.4 ) — — Operating income (loss) $ (1,301.9 ) $ 354.3 $ 171.3
Reconciliation of Assets from Segment to Consolidated	The table below represents information about segment assets as of December 31, 2015 and 2014 (in millions): Year Ended December 31, Segment Identifiable Assets: 2015 2014 Texas $ 3,709.5 $ 3,302.9 Louisiana 2,309.3 3,316.5 Oklahoma 873.4 892.8 Crude and Condensate 898.0 871.8 Corporate 1,774.9 1,822.7 Total identifiable assets $ 9,565.1 $ 10,206.7

Quarterly Financial Data (Una45

Quarterly Financial Data (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Summarized unaudited quarterly financial data is presented below. First Second Third Fourth Total (In millions, except per unit data) 2015: Revenues $ 940.5 $ 1,274.5 $ 1,170.6 $ 1,066.5 $ 4,452.1 Impairments $ — $ — $ 799.2 $ 764.2 $ 1,563.4 Operating income (loss) $ 50.5 $ 71.4 $ (731.8 ) $ (692.0 ) $ (1,301.9 ) Net income (loss) attributable to the non-controlling interest $ 8.0 $ 28.4 $ (562.5 ) $ (528.4 ) $ (1,054.5 ) Net income (loss) attributable to EnLink Midstream, LLC $ 17.0 $ 16.2 $ (193.4 ) $ (195.0 ) $ (355.2 ) Net income (loss) per common unit-basic $ 0.10 $ 0.09 $ (1.18 ) $ (1.18 ) $ (2.17 ) Net income (loss) per common unit-diluted $ 0.10 $ 0.09 $ (1.18 ) $ (1.18 ) $ (2.17 ) 2014: Revenues $ 723.0 $ 927.2 $ 857.4 $ 1,000.2 $ 3,507.8 Operating income $ 73.1 $ 89.8 $ 87.0 $ 104.4 354.3 Net income attributable to the non-controlling interest $ 7.1 $ 35.7 $ 37.7 $ 46.2 $ 126.7 Net income attributable to EnLink Midstream, LLC $ 41.4 $ 26.7 $ 26.5 $ 29.4 $ 124.0 Net income per limited partner unit-basic $ 0.04 $ 0.18 $ 0.18 $ 0.16 $ 0.55 Net income per limited partner unit-diluted $ 0.04 $ 0.18 $ 0.17 $ 0.16 $ 0.55

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	The following schedule summarizes net income from discontinued operations (in millions): Year Ended December 31, 2014 2013 Revenues: Revenues $ 6.8 $ 42.1 Revenues - affiliates 10.5 84.6 Total revenues 17.3 126.7 Operating costs and expenses: Operating expenses 15.7 130.3 Total operating costs expenses 15.7 130.3 Income (loss) before income taxes 1.6 (3.6 ) Income tax provision (benefit) 0.6 (1.3 ) Net income (loss) 1.0 (2.3 ) Net income attributable to non-controlling interest — (1.3 ) Net income (loss) including non-controlling interest $ 1.0 $ (3.6 )

Supplemental Cash Flow Inform47

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following schedule summarizes the Partnership's non-cash financing activities for the period presented. December 31, 2015 (In millions) Non-cash financing activities: Non-cash issuance of common units (1) $ 180.0 Non-cash issuance of Class C Common Units (1) $ 180.0 ____________________________________________________________________________ (1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.

Other Information (Tables)

Other Information (Tables)	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	Other current liabilities consisted of the following: Year Ended December 31, 2015 2014 (in millions) Accrued interest $ 23.2 $ 16.9 Accrued wages and benefits, including taxes 27.7 19.7 Accrued ad valorem taxes 27.0 23.2 Capital expenditure accruals 22.3 22.6 Onerous performance obligation 17.0 20.3 Other 57.6 49.6 Other current liabilities $ 174.8 $ 152.3

Organization and Summary of S49

Organization and Summary of Significant Agreements (Details Textuals) - shares	May. 27, 2015	Feb. 17, 2015	Oct. 22, 2014	Mar. 07, 2014	Dec. 31, 2015
Business Acquisition [Line Items]
Partnership name					EnLink Midstream Partners GP, LLC
Total units exchanged			1,000,000	115,495,669
EMI [Member]
Business Acquisition [Line Items]
Limited partner interest					6.10%
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited partner interest				7.10%	26.50%
Common units					88,528,451
Ownership interest					0.50%
Devon Energy Corporation
Business Acquisition [Line Items]
Limited partner interest					70.00%
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Limited partner interest				50.00%
Enlink midstream, LLC
Business Acquisition [Line Items]
Limited partner interest				50.00%
Ownership interest				100.00%	100.00%
Affiliated Entity | EMH Drop Down [Member] | Midstream Holdings [Member] | EnLink Midstream LP [Member]
Business Acquisition [Line Items]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%
EnLink Midstream LP [Member] | Affiliated Entity | EMH Drop Down [Member] | EnLink Midstream Holdings, LP | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Related Party Transaction, Ownership Interest Transferred	25.00%	25.00%
Class E Common Unit [Member] | EnLink Midstream LP [Member] | Affiliated Entity | EMH Drop Down [Member] | EnLink Midstream Holdings, LP | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Limited partner interest					11.00%
Related Party Transaction, Amounts of Transaction, Shares	36,629,888
Class D Common Unit [Member] | EnLink Midstream LP [Member] | Affiliated Entity | EMH Drop Down [Member] | EnLink Midstream Holdings, LP | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Limited partner interest					9.50%
Related Party Transaction, Amounts of Transaction, Shares		31,618,311

Significant Accounting Polici50

Significant Accounting Policies (Gas Imbalances and Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Gas Imbalance Asset Liability [Abstract]
Gas Balancing Payable	$ 2.6	$ 1.5
Gas Balancing Receivable	3.6	1.2
Other Assets [Abstract]
Unamortized debt issuance costs	$ 23.8	$ 17.5

Significant Accounting Polici51

Significant Accounting Policies (Property Plant and Equipment) (Details Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 7,424,400,000	$ 6,469,100,000
Accumulated depreciation	(1,757,600,000)	(1,426,300,000)
Property, plant and equipment, net	5,666,800,000	5,042,800,000
Depreciation expense	331,300,000	247,800,000	$ 187,000,000
Gain (Loss) on Disposition of Property Plant Equipment	(1,200,000)	100,000	0
Impaired Assets to be Disposed of by Method Other than Sale, Carrying Value of Asset	5,100,000
Proceeds from Insurance Settlement, Investing Activities	2,900,000	0	0
Proceeds from Sale of Property, Plant, and Equipment	1,000,000	100,000	0
Gain on Business Interruption Insurance Recovery	2,400,000
Depreciation, Depletion and Amortization, Nonproduction	387,300,000	284,300,000	$ 187,000,000
Tangible Asset Impairment Charges	12,100,000
Transmission Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 1,285,100,000	1,100,100,000
Transmission Assets | Maximum
Property, Plant and Equipment [Line Items]
Useful Life	25 years
Transmission Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful Life	20 years
Gathering Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 2,999,200,000	2,391,900,000
Gathering Assets | Maximum
Property, Plant and Equipment [Line Items]
Useful Life	25 years
Gathering Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful Life	20 years
Gas Processing Plants
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 2,673,700,000	2,356,100,000
Gas Processing Plants | Maximum
Property, Plant and Equipment [Line Items]
Useful Life	25 years
Gas Processing Plants | Minimum
Property, Plant and Equipment [Line Items]
Useful Life	20 years
Other Property and Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 135,900,000	379,500,000
Other Property and Equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful Life	15 years
Other Property and Equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful Life	3 years
Construction in Progress
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 330,500,000	241,500,000
Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Change in Accounting Estimate, Financial Effect		29,400,000
Depreciation Per Share [Member]
Property, Plant and Equipment [Line Items]
Change in Accounting Estimate, Financial Effect		$ 0.18

Significant Accounting Polici52

Significant Accounting Policies (Goodwill) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Accounting Policies [Abstract]
Goodwill, Impairment Loss	$ 1,328.2

Significant Accounting Polici53

Significant Accounting Policies (Intangible Assets) (Details)	12 Months Ended
	Dec. 31, 2015
Minimum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	20 years

Significant Accounting Polici54

Significant Accounting Policies (Other Long Term Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Commitments [Line Items]
Contract liability	$ 62.8	$ 80.7

Significant Accounting Polici55

Significant Accounting Policies (Concentraction of Credit Risk) (Details Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Allowance for Doubtful Accounts Receivable	$ 300,000	$ 0
Concentration Risk, Percentage	10.00%
Devon Energy Corporation
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.60%	30.60%	92.20%
Third Party [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.70%	11.00%

Significant Accounting Polici56

Significant Accounting Policies (Environmental Cost) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Environmental Exit Cost [Line Items]
Environmental Remediation Expense	$ 3.5

Acquisition (Textual) (Details)

Acquisition (Textual) (Details) - USD ($) $ in Millions	Nov. 16, 2015	Oct. 01, 2015	Apr. 01, 2015	Mar. 16, 2015	Jan. 31, 2015	Nov. 01, 2014	Oct. 22, 2014	Mar. 07, 2014	Nov. 30, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Total units exchanged							1,000,000	115,495,669
Business Acquisition, Transaction Costs								$ 51.4
Equity interests issued and issuable							$ 31.2
Payments to Acquire Additional Interest in Subsidiaries													$ 0	$ 12.5	$ 0
Distribution To Parent For Asset Drop			$ 35.7
Contributions From Devon													25.6
Chevron Acquisition
Business Acquisition [Line Items]
Useful Life						20 years
Percentage of Voting Interests Acquired						100.00%
Business Acquisition, Transaction Costs										$ 0.6	$ 0.6	$ 0.6	0.6
Payments to Acquire Businesses, Gross									$ 231.5
LPC [Member]
Business Acquisition [Line Items]
Useful Life					10 years
Consideration Transferred					$ 108.1
Business Combination, Consideration Transferred, Other					$ 87
Percentage of Voting Interests Acquired					100.00%
Business Acquisition, Transaction Costs										0.3	0.3	0.3	0.3
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual												1,100
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual												(0.9)
Coronado [Member]
Business Acquisition [Line Items]
Useful Life				10 years
Consideration Transferred				$ 600.3
Business Combination, Initial Cash Consideration				240.3
Business Combination, Consideration Transferred, Other				$ 238.9
Percentage of Voting Interests Acquired				100.00%
Total units exchanged				6,704,285
Business Acquisition, Transaction Costs										3.1	3.1	3.1	3.1
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual											182
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual											14.2
VEX Pipeline [Member]
Business Acquisition [Line Items]
Percentage of Voting Interests Acquired			100.00%
Total units exchanged			338,159
Payments to Acquire Businesses, Gross			$ 166.7
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned			9
Capitalized Costs, Support Equipment and Facilities			40
Business Combination, Historical Cost of Entity Under Common Control			$ 131
Matador [Member]
Business Acquisition [Line Items]
Useful Life		20 years
Consideration Transferred		$ 145.3
Percentage of Voting Interests Acquired		100.00%
Business Acquisition, Transaction Costs										0.1	0.1	0.1	0.1
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		$ 5.6
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual		$ 0.7
Deadwood Acquisition [Member] [Member]
Business Acquisition [Line Items]
Consideration Transferred	$ 40
Percentage of Voting Interests Acquired	50.00%
Business Acquisition, Transaction Costs										0.1	$ 0.1	$ 0.1	$ 0.1
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual										3.5
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual										$ (1.3)
Gulf Coast Fractionators
Business Acquisition [Line Items]
Ownership Percentage								38.75%		38.75%	38.75%	38.75%	38.75%
Common Class C [Member] | Coronado [Member]
Business Acquisition [Line Items]
Total units exchanged				6,704,285
Enlink midstream, LLC
Business Acquisition [Line Items]
Limited partner interest								50.00%
Ownership interest								100.00%					100.00%
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited partner interest								7.10%					26.50%
Ownership interest													0.50%
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Percentage of Voting Interests Acquired								50.00%
Limited partner interest								50.00%

Acquisition (Details)

Acquisition (Details) - USD ($) $ in Millions	Oct. 01, 2015	Mar. 16, 2015	Jan. 31, 2015	Oct. 22, 2014	Mar. 07, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Nov. 01, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Total units exchanged				1,000,000	115,495,669
Assets acquired [Abstract]
Goodwill						$ 2,413.9	$ 2,413.9	$ 3,684.7		$ 401.7
Matador [Member]
Business Acquisition [Line Items]
Consideration Transferred	$ 145.3
Assets acquired [Abstract]
Current assets	1.9
Property, plant and equipment	35.5
Intangibles	98.8
Goodwill	9.1
Liabilities assumed:
Net assets acquired	145.3
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 5.6
Coronado [Member]
Business Acquisition [Line Items]
Total units exchanged		6,704,285
Consideration Transferred		$ 600.3
Assets acquired [Abstract]
Current assets		20.8
Property, plant and equipment		302.1
Intangibles		281
Goodwill		18.7
Liabilities assumed:
Current liabilities		(22.3)
Net assets acquired		$ 600.3
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual						$ 182
LPC [Member]
Business Acquisition [Line Items]
Consideration Transferred			$ 108.1
Assets acquired [Abstract]
Current assets			107.4
Property, plant and equipment			29.8
Intangibles			43.2
Goodwill			29.6
Liabilities assumed:
Current liabilities			(97.9)
Deferred taxes			(4)
Net assets acquired			$ 108.1
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							$ 1,100
Chevron Acquisition
Assets acquired [Abstract]
Property, plant and equipment									$ 225.3
Intangibles									13
Liabilities assumed:
Current liabilities									(6.8)
Net assets acquired									$ 231.5

Acquisition (Proforma) (Details

Acquisition (Proforma) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Pro forma total revenues	$ 4,585.5	$ 5,679.3
Pro forma net income	(1,413)	220.2
Pro forma net income attributable to EnLink Midstream, LLC	$ (355.5)	$ 64.8
Pro forma net income per common unit: Basic (usd per unit)	$ (2.18)	$ 0.41
Pro forma net income per common unit: Diluted (usd per unit)	$ (2.18)	$ 0.41

Acquisition (Recast) (Details)

Acquisition (Recast) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 1,066.5	$ 1,170.6	$ 1,274.5	$ 940.5	$ 1,000.2	$ 857.4	$ 927.2	$ 723	$ 4,452.1	$ 3,507.8	$ 2,295.9
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest									(1,409.7)	250.7	115.5
Net income (loss) attributable to the non-controlling interest	(528.4)	(562.5)	28.4	8	46.2	37.7	35.7	7.1	(1,054.5)	126.7	0
Net Income (Loss) Attributable to Parent	$ (195)	$ (193.4)	$ 16.2	$ 17	$ 29.4	$ 26.5	$ 26.7	$ 41.4	(355.2)	124	115.5
Enlink Midstream, LLC interest in net income (loss)									(357)	90.5	$ 0
VEX [Member]
Business Acquisition [Line Items]
Revenues									5.3	7.4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest									1.8	(2)
Net income (loss) attributable to the non-controlling interest									0	0
Net Income (Loss) Attributable to Parent									1.8	(2)
Enlink Midstream, LLC interest in net income (loss)									0	0
ENLC Historical [Member]
Business Acquisition [Line Items]
Revenues									4,446.8	3,500.4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest									(1,411.5)	252.7
Net income (loss) attributable to the non-controlling interest									(1,054.5)	126.7
Net Income (Loss) Attributable to Parent									(357)	126
Enlink Midstream, LLC interest in net income (loss)									$ (357)	$ 90.5

Acquisition (Phantom) (Details)

Acquisition (Phantom) (Details) - USD ($) $ in Millions	Mar. 16, 2015	Jan. 31, 2015
LPC [Member]
Business Acquisition [Line Items]
Cash Acquired from Acquisition		$ 21.1
Coronado [Member]
Business Acquisition [Line Items]
Cash Acquired from Acquisition	$ 1.4

Goodwill and Intangible Asset62

Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Impairments	$ 764.2	$ 799.2	$ 0	$ 0	$ 1,563.4	$ 0	$ 0
Goodwill	2,413.9				2,413.9	3,684.7	401.7
Goodwill, Acquired During Period					57.4	3,283
Goodwill, Impairment Loss					$ (1,328.2)
Minimum [Member]
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life					10 years
Maximum [Member]
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life					20 years
Corporate Segment
Goodwill [Line Items]
Impairments					$ 0
Goodwill	1,426.9				1,426.9	1,426.9	0
Goodwill, Acquired During Period					0	1,426.9
Goodwill, Impairment Loss					0
Crude And Condensate Segment
Goodwill [Line Items]
Impairments					279.2
Goodwill	93.2				93.2	112.5	0
Goodwill, Acquired During Period					29.6	112.5
Goodwill, Impairment Loss					(48.9)
Oklahoma Operating Segment
Goodwill [Line Items]
Impairments					0.6
Goodwill	190.3				190.3	190.3	76.3
Goodwill, Acquired During Period					0	114
Goodwill, Impairment Loss					0
Louisiana Operating Segment
Goodwill [Line Items]
Impairments					787.3
Goodwill	0				0	786.8	0
Goodwill, Acquired During Period					0	786.8
Goodwill, Impairment Loss					(786.8)
Texas Operating Segment
Goodwill [Line Items]
Impairments					496.3
Goodwill	$ 703.5				703.5	1,168.2	$ 325.4
Goodwill, Acquired During Period					27.8	$ 842.8
Goodwill, Impairment Loss					$ (492.5)

Goodwill and Intangible Asset63

Goodwill and Intangible Assets (Intangible Asset by Major Class) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquired Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	12 years 7 months
Finite-Lived Intangible Assets, Gross	$ 744.5	$ 569.5	$ 0
Finite-Lived Intangible Assets, Accumulated Amortization	54.6	36.5	0
Total	689.9	533	$ 0
Finite-lived Intangible Assets Acquired	436	569.5
Amortization of Intangible Assets	56	$ 36.5
ImpairmentOfIntangibleAssetsFinitelivedGross	261
Accumulated Depreciation, Depletion and Amortization, Reclassifications from Property, Plant and Equipment	37.9
Impairment of Intangible Assets, Finite-lived	$ 223.1

Goodwill and Intangible Asset64

Goodwill and Intangible Assets (Amortization Expense Table) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2,016	$ 46.1
2,017	46.1
2,018	46.1
2,019	46.1
2,020	46.1
Thereafter	459.4
Total	$ 689.9	$ 533	$ 0

Affiliate Transactions (Textual

Affiliate Transactions (Textual) (Details) - USD ($) $ in Millions		May. 27, 2015	Feb. 17, 2015	Oct. 22, 2014	Mar. 07, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Distributions Not Transferred To Related Party								$ 5.5
Gross Profit						$ 786.9	$ 735.8	403.4
Concentration Risk, Percentage						10.00%
Due from Affiliate, Current						$ 110.8	121.6
Due to Related Parties, Current						14.8	3
Allocated Share-based Compensation Expense						36.1	22.4	12.8
General and administrative expenses	[1]					$ 136.9	$ 97.3	$ 45.1
Total units exchanged				1,000,000	115,495,669
Equity interests issued and issuable				$ 31.2
Devon Energy Corporation
Related Party Transaction [Line Items]
Concentration Risk, Percentage						16.60%	30.60%	92.20%
Allocated Share-based Compensation Expense							$ 2.8	$ 12.8
Pension and Other Postretirement Benefit Expense							1.6	8.7
Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses						$ 0.2	11.6	$ 45.1
Transmission Service Agreement [Member] | Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses						0.2	3
Other Income						$ 0.3	$ 0.3
Gulf Coast Fractionators
Related Party Transaction [Line Items]
Ownership Percentage					38.75%	38.75%
E2 [Member]
Related Party Transaction [Line Items]
Consideration Transferred				194
Payments to Acquire Businesses, Gross				$ 163
EMH Drop Down [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Affiliated Entity
Related Party Transaction [Line Items]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions		100.00%
EMH Drop Down [Member] | Acacia [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | EnLink Midstream Holdings, LP | Affiliated Entity
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 900	$ 925
EMH Drop Down [Member] | Acacia [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Class E Common Unit [Member] | EnLink Midstream Holdings, LP | Affiliated Entity
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction, Shares		36,629,888
EMH Drop Down [Member] | Acacia [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Class D Common Unit [Member] | EnLink Midstream Holdings, LP | Affiliated Entity
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction, Shares			31,618,311
[1]	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.

Affiliate Transactions (Predece

Affiliate Transactions (Predecessor's Affiliate Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Accounts payable to related party	$ 14.8	$ 3
Net cash used in financing activities	418.5	758.1	$ (151.2)
Capital expenditures	570.5	758.7	213.1
Net distributions from (to) related party		(71.9)	(279.6)
Affiliated Entity
Related Party Transaction [Line Items]
Operating expenses - affiliates	$ 0.5	5.9	36.2
Continuing Operations | Affiliated Entity
Related Party Transaction [Line Items]
Total Operating Revenue- Affiliate		436.4	2,116.5
Operating expenses - affiliates		340	1,669.5
Net affiliate transactions		96.4	447
Capital expenditures		16.2	244.3
Other third-party transactions, net		58.9	51.5
Net third-party transactions		75.1	295.8
Net distributions from (to) related party		(27.6)	(151.2)
Net distributions from (to) related party, non-cash		6.3	0
Continuing Operations | Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party		(21.3)	(151.2)
Discontinued Operations
Related Party Transaction [Line Items]
Net distributions from (to) related party		(4.4)	(128.4)
Discontinued Operations | Affiliated Entity
Related Party Transaction [Line Items]
Total Operating Revenue- Affiliate		10.4	84.6
Operating expenses - affiliates		5	32.7
Net cash used in financing activities		0	(5.6)
Net affiliate transactions		5.4	57.5
Capital expenditures		0.6	1.1
Other Operating Income (Expense)		0.4	(72)
Net third-party transactions		1	(70.9)
Net distributions from (to) related party		(44.3)	(128.4)
Discontinued Operations | Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party, non-cash		$ 39.9	$ 0

Affiliate Transactions (Phantom

Affiliate Transactions (Phantom) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Transmission Service Agreement [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Other Income	$ 0.3	$ 0.3

Long-Term Debt (Indebtedness Ta

Long-Term Debt (Indebtedness Table) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt	$ 0	$ 3.2	$ 0
Total outstanding debt	3,089.8	2,022.5
Line of Credit Facility, Amount Outstanding	414	237
Other Long-term Debt	0.2	0.4
Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding		237
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	0	0
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior Notes	$ 399.6	399.5
Debt Instrument, Repurchase Date	Mar. 1, 2019
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt		2.4
Senior Notes	$ 181.4	184.4
Debt Instrument, Repurchase Date	Jul. 20, 2014
8.875% Senior Notes due 2018
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt		0.7
Debt Instrument, Repurchase Date	Mar. 12, 2014
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes	$ 552.9	553.2
Debt Instrument, Repurchase Date	Jan. 1, 2024
4.15% Senior Notes due 2025
Debt Instrument [Line Items]
Senior Notes	$ 748.8	0
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior Notes	$ 349.8	349.7
Debt Instrument, Repurchase Date	Oct. 1, 2043
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior Notes	$ 443.1	$ 298.3
Debt Instrument, Repurchase Date	Oct. 1, 2044

Long-Term Debt (Long Term debt

Long-Term Debt (Long Term debt Maturities Schedule) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Maturities of Long-term Debt [Abstract]
2,015	$ 0.1
2,016	0.1
2,017	0
2,018	400
2,019	414
Thereafter	2,262.5
Subtotal	3,076.7
Less: premium (discount)	13.1
Total outstanding debt	$ 3,089.8	$ 2,022.5

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($)

Mar. 12, 2014

Mar. 07, 2014

Dec. 31, 2015

May. 12, 2015

Feb. 05, 2015

Dec. 31, 2014

Nov. 12, 2014

Sep. 20, 2014

Jul. 20, 2014

Apr. 18, 2014

Mar. 19, 2014

Feb. 20, 2014

Debt Instrument [Line Items]

Line of Credit Facility, Initiation Date

Feb. 20, 2014

Long-term Debt

$ 3,089,800,000

$ 2,022,500,000

Debt Instrument, Unamortized Discount (Premium), Net

13,100,000

Maximum borrowing capacity

1,500,000,000

$ 1,500,000,000

$ 1,000,000,000

Line Of Credit Facility, Additional Borrowing Limit

500,000,000

Letters of Credit Outstanding, Amount

10,900,000

Line of Credit Facility, Amount Outstanding

414,000,000

237,000,000

Line of Credit Facility, Remaining Borrowing Capacity

1,075,000,000

Other Long-term Debt

$ 200,000

$ 400,000

EnLink Midstream Partners GP, LLC

Debt Instrument [Line Items]

Limited partner interest

100.00%

Enlink Midstream, Inc.

Debt Instrument [Line Items]

Common units

88,528,451

Limited partner interest

7.10%

26.50%

Minimum

Debt Instrument [Line Items]

Interest Coverge Ratio

2.50

Maximum

Debt Instrument [Line Items]

Leverage ratios

5

Conditional acquisition purchase price

$ 50,000,000

Revolving Credit Facility | Maximum

Debt Instrument [Line Items]

Leverage ratios

5.5

Base Rate

Debt Instrument [Line Items]

Variable Interest Rate

0.50%

Eurodollar | Revolving Credit Facility

Debt Instrument [Line Items]

Variable Interest Rate

1.00%

Unsecured Debt

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

Mar. 19, 2014

Debt Instrument, Face Amount

$ 900,000,000

$ 1,200,000,000

5.05% Senior Notes due 2045

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 150,000,000

$ 300,000,000

Senior notes fixed interest rate

5.05%

5.05%

5.05%

5.05%

Senior Notes

$ 443,100,000

$ 298,300,000

Selling Priceof Debt Instrument

96.381%

99.452%

Debt Instrument, Unamortized Discount (Premium), Net

$ (6,900,000)

$ (1,700,000)

Debt Instrument Repurchase, Tendered Offer Date

Oct. 1, 2044

Redemption price

100.00%

5.6% Senior Notes due 2044

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 350,000,000

Senior notes fixed interest rate

5.60%

5.60%

5.60%

Senior Notes

$ 349,800,000

$ 349,700,000

Debt Instrument, Maturity Date

Apr. 1, 2044

Selling Priceof Debt Instrument

99.925%

Debt Instrument, Unamortized Discount (Premium), Net

$ (200,000)

$ (300,000)

Debt Instrument Repurchase, Tendered Offer Date

Oct. 1, 2043

Redemption price

100.00%

4.4% Senior Notes due 2024

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 100,000,000

$ 450,000,000

Senior notes fixed interest rate

4.40%

4.40%

4.40%

Senior Notes

$ 552,900,000

$ 553,200,000

Debt Instrument, Maturity Date

Apr. 1, 2024

Selling Priceof Debt Instrument

104.007%

99.83%

Debt Instrument, Unamortized Discount (Premium), Net

$ 2,900,000

$ 3,200,000

Debt Instrument Repurchase, Tendered Offer Date

Jan. 1, 2024

Redemption price

100.00%

4.15% Senior Notes due 2025

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 750,000,000

Senior notes fixed interest rate

4.15%

4.15%

0.00%

Senior Notes

$ 748,800,000

$ 0

Selling Priceof Debt Instrument

99.827%

Debt Instrument, Unamortized Discount (Premium), Net

$ (1,200,000)

$ 0

4.15% Senior Notes due 2025 | Debt Instrument, Redemption, Period One [Member]

Debt Instrument [Line Items]

Redemption price

100.00%

4.15% Senior Notes due 2025 | Debt Instrument, Redemption, Period Two [Member]

Debt Instrument [Line Items]

Redemption price

100.00%

2.7% Senior Notes due 2019

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 400,000,000

Senior notes fixed interest rate

2.70%

2.70%

2.70%

Senior Notes

$ 399,600,000

$ 399,500,000

Debt Instrument, Maturity Date

Apr. 1, 2019

Selling Priceof Debt Instrument

99.85%

Debt Instrument, Unamortized Discount (Premium), Net

$ (400,000)

$ (500,000)

Debt Instrument Repurchase, Tendered Offer Date

Mar. 1, 2019

Redemption price

100.00%

7.125% Senior Notes due 2022

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 196,500,000

Senior notes fixed interest rate

7.125%

7.125%

7.125%

Senior Notes

$ 181,400,000

$ 184,400,000

Debt Instrument, Maturity Date

Jun. 1, 2022

Long-term Debt, Fair Value

$ 226,000,000

Debt Instrument, Unamortized Discount (Premium), Net

29,500,000

$ 18,900,000

21,900,000

Debt Instrument Repurchase, Tendered Offer Date

Jul. 20, 2014

Debt Instrument Repurchase, Tendered Amount

$ 15,500,000

$ 18,500,000

Debt Instrument Repurchase, Amount Paid

$ 17,000,000

$ 20,000,000

7.125% Senior Notes due 2022 | September Redemption

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Sep. 20, 2014

7.125% Senior Notes due 2022 | Debt Instrument, Redemption, Period One [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Jun. 1, 2017

Redemption price

103.563%

7.125% Senior Notes due 2022 | Debt Instrument, Redemption, Period Two [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Jun. 1, 2018

Redemption price

102.375%

7.125% Senior Notes due 2022 | Debt Instrument, Redemption, Period Three [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Jun. 1, 2019

Redemption price

101.188%

7.125% Senior Notes due 2022 | Debt Instrument, Redemption, Period Four [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Jun. 1, 2020

Redemption price

100.00%

8.875% Senior Notes due 2018

Debt Instrument [Line Items]

Debt Instrument, Face Amount

$ 725,000,000

Senior notes fixed interest rate

8.875%

Debt Instrument, Maturity Date

Feb. 15, 2018

Long-term Debt, Fair Value

$ 761,300,000

Debt Instrument, Unamortized Discount (Premium), Net

36,300,000

Debt Instrument Repurchase, Tendered Offer Date

Mar. 12, 2014

Debt Instrument Repurchase, Tendered Amount

$ 536,100,000

Debt Instrument Repurchase, Amount of Outstanding Tendered, Percent

74.00%

8.875% Senior Notes due 2018 | Debt Instrument, Redemption, Period One [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Mar. 19, 2014

Debt Instrument Repurchase, Amount Paid

$ 567,400,000

8.875% Senior Notes due 2018 | Debt Instrument, Redemption, Period Two [Member]

Debt Instrument [Line Items]

Debt Instrument Repurchase, Tendered Offer Date

Apr. 18, 2014

Debt Instrument Repurchase, Amount Paid

$ 200,200,000

Letter of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

125,000,000

$ 500,000,000

ENLC Credit Facility [Member]

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 250,000,000

$ 250,000,000

Line of Credit Facility, Amount Outstanding

0

$ 0

Line of Credit Facility, Remaining Borrowing Capacity

$ 250,000,000

ENLC Credit Facility [Member] | Maximum

Debt Instrument [Line Items]

Leverage ratios

4

ENLC Credit Facility [Member] | AcquisitionPeriod [Member] | Maximum

Debt Instrument [Line Items]

Leverage ratios

4.50

ENLC Credit Facility [Member] | Eurodollar | Revolving Credit Facility

Debt Instrument [Line Items]

Percentage Rate

1.00%

Long-Term Debt (Percentages Per

Long-Term Debt (Percentages Per Annum) (Details)	12 Months Ended
	Dec. 31, 2015
Standard & Poor's, BBB Rating | Moody's, Baa1 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BBB+/Baa1
Applicable Rate Commitment Fee	0.125%
Base Rate	0.125%
Standard & Poor's, BBB Rating | Moody's, Baa1 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.125%
Standard & Poor's, BBB Rating | Moody's, Baa2 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BBB/Baa2
Applicable Rate Commitment Fee	0.175%
Base Rate	0.25%
Standard & Poor's, BBB Rating | Moody's, Baa2 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.25%
Standard & Poor's, BBB- | Moody's, Baa3 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BBB-/Baa3
Applicable Rate Commitment Fee	0.225%
Base Rate	0.50%
Standard & Poor's, BBB- | Moody's, Baa3 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.50%
Standard & Poor's, BB | Moody's, Ba1 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BB+/Ba1
Applicable Rate Commitment Fee	0.275%
Base Rate	0.625%
Standard & Poor's, BB | Moody's, Ba1 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.625%
Minimum | Standard & Poor's, A- Rating | Moody's, A3 Rating
Line of Credit Facility [Line Items]
Debt Ratings	A-/A3 or better
Applicable Rate Commitment Fee	0.10%
Base Rate	0.00%
Minimum | Standard & Poor's, A- Rating | Moody's, A3 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.00%
Maximum | Standard & Poor's, BB Rating | Moody's, Ba2 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BB/Ba2 or worse
Applicable Rate Commitment Fee	0.35%
Base Rate	0.75%
Maximum | Standard & Poor's, BB Rating | Moody's, Ba2 Rating | Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.75%

Long-Term Debt (Phantom Interes

Long-Term Debt (Phantom Interest Rates) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	May. 12, 2015	Nov. 12, 2014	Mar. 19, 2014	Mar. 07, 2014
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ 13,100,000
Line of Credit
Debt Instrument [Line Items]
EuroDollar Rate/Letter of Credit	1.80%	1.90%
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Mar. 1, 2019
Senior notes fixed interest rate	2.70%	2.70%			2.70%
Debt Instrument, Unamortized Discount (Premium), Net	$ (400,000)	$ (500,000)
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Jan. 1, 2024
Senior notes fixed interest rate	4.40%	4.40%			4.40%
Debt Instrument, Unamortized Discount (Premium), Net	$ 2,900,000	$ 3,200,000
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Oct. 1, 2043
Senior notes fixed interest rate	5.60%	5.60%			5.60%
Debt Instrument, Unamortized Discount (Premium), Net	$ (200,000)	$ (300,000)
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Jul. 20, 2014
Senior notes fixed interest rate	7.125%	7.125%				7.125%
Debt Instrument, Unamortized Discount (Premium), Net	$ 18,900,000	$ 21,900,000				$ 29,500,000
8.875% Senior Notes due 2018
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Mar. 12, 2014
Senior notes fixed interest rate						8.875%
Debt Instrument, Unamortized Discount (Premium), Net						$ 36,300,000
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Repurchase Date	Oct. 1, 2044
Senior notes fixed interest rate	5.05%	5.05%	5.05%	5.05%
Debt Instrument, Unamortized Discount (Premium), Net	$ (6,900,000)	$ (1,700,000)
4.15% Senior Notes due 2025
Debt Instrument [Line Items]
Senior notes fixed interest rate	4.15%	0.00%	4.15%
Debt Instrument, Unamortized Discount (Premium), Net	$ (1,200,000)	$ 0

Income Taxes (Textuals) (Detail

Income Taxes (Textuals) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Deferred Tax Assets, Operating Loss Carryforwards, Domestic, Non Current	$ 20.9	$ 0
Deferred Tax Assets, Net	3.6	$ 4.2
Federal
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	59.8
Deferred Tax Assets, Operating Loss Carryforwards, Domestic, Non Current	20.9
State and Local
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	141
Deferred Tax Assets, Net	$ 3.6

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense Benefit Tables) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current tax expense	$ 3.1	$ 9	$ 31.5
Deferred tax expense	22.6	67.4	35.5
Expected income tax expense (benefit) based on federal statutory rate of 35%	(116)	70.7	65.1
State income taxes, net of federal benefit and other	(7.7)	5.7	1.9
Other Tax Expense (Benefit)	149.4	0	0
Total income tax expense	$ 25.7	$ 76.4	$ 67

Income Taxes (Deferred Tax Liab

Income Taxes (Deferred Tax Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal net operating loss carryforward, non current	$ 0	$ 16.9
Deferred Tax Assets, Gross, Current	0	16.9
Asset retirement obligations and other	2.3	2
State net operating loss carryforward, non current	3.6	4.2
Deferred Tax Assets, Operating Loss Carryforwards, Domestic, Non Current	20.9	0
Deferred Tax Assets, Gross, Noncurrent	26.8	6.2
Deferred Tax Assets, Gross	26.8	23.1
Property, plant, equipment, and intangible assets, non current	(557.6)	(523.5)
Other	(1.3)	(9.3)
Total non current deferred tax liabilities	(558.9)	(532.8)
Deferred tax liability, net	$ (532.1)	$ (509.7)

Income Taxes (Unrecognized Tax

Income Taxes (Unrecognized Tax Liability) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits	$ 1.5	$ 2	$ 0
Unrecognized tax positions assumed in merger	0	3.8
Decrease due to prior year tax positions	(0.5)	(2)
Increases due to current year tax positions	$ 0	$ 0.2

Certain Provision of the Partne

Certain Provision of the Partnership Agreement (Textual) (Details) - USD ($)

Oct. 29, 2015

May. 27, 2015

Mar. 16, 2015

Feb. 17, 2015

Nov. 30, 2014

Oct. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Mar. 31, 2014

Jun. 30, 2014

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Subsidiary Sale Of Stock [Line Items]

Partners' Capital Account, Units, Sold in Public Offering

12,075,000

Incentive Distribution, Distribution

$ 47,500,000

Distributions Declared, Per Unit

$ 0.39

$ 0.385

$ 0.38

$ 0.375

$ 0.370

$ 0.36

$ 0.365

$ 0.39

Shares Issued, Price Per Share

$ 17.55

$ 28.37

Proceeds from Issuance of Common Limited Partners Units

$ 332,300,000

$ 24,400,000

$ 412,000,000

$ 0

Issuance of Common Shares to Parent In a Private Placement

2,849,100

Proceeds from Issuance of Common Stock

$ 50,000,000

Percentage Of Avaliable Cash to Distribute

100.00%

100.00%

Distribution Made to Limited Partner, Distribution Period

45 days

Distribution Made to Limited Partner, Distribution Date

Feb. 11, 2016

Aug. 13, 2015

May 14, 2015

Feb. 12, 2015

Nov. 13, 2014

May 14, 2014

Aug. 13, 2014

Nov. 12, 2015

Common Class C [Member]

Subsidiary Sale Of Stock [Line Items]

Distributions Declared, Per Unit

$ 0.390

Stock Issued During Period, Shares, Acquisitions

6,704,285

Paid In Kind Dividends

209,044

150,732

120,622

99,794

General Partner Interest

Subsidiary Sale Of Stock [Line Items]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 1.530

General Partner Interest | 13% Distribution

Subsidiary Sale Of Stock [Line Items]

Incentive Distribution Percentage Levels

13.00%

Incentive Distribution, Distribution Per Unit

$ 0.25

General Partner Interest | 23% Distribution

Subsidiary Sale Of Stock [Line Items]

Incentive Distribution Percentage Levels

23.00%

Incentive Distribution, Distribution Per Unit

$ 0.3125

General Partner Interest | 48% Distribution

Subsidiary Sale Of Stock [Line Items]

Incentive Distribution Percentage Levels

48.00%

Incentive Distribution, Distribution Per Unit

$ 0.375

Enlink midstream, LLC | E2 Appalachian Compression, LLC

Subsidiary Sale Of Stock [Line Items]

Partners' Capital Account, Units, Sale of Units

1,016,322

BMO Capital Markets Corp. | EDA [Member]

Subsidiary Sale Of Stock [Line Items]

Proceeds from Issuance of Common Limited Partners Units

71,900,000

Payments of Stock Issuance Costs

$ 700,000

AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement

$ 317,000,000

$ 317,000,000

AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement

$ 75,000,000

75,000,000

Partners' Capital Account, Units, Sold in Private Placement

2,400,000

BMO Capital Markets Corp, Merrilly Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc, Jeffries LLC, Raymond James and Associates, Inc and RBC Capital Markets LLC | EDA [Member]

Subsidiary Sale Of Stock [Line Items]

Proceeds from Issuance of Common Limited Partners Units

24,400,000

Payments of Stock Issuance Costs

$ 300,000

AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement

$ 350,000,000

Partners' Capital Account, Units, Sold in Private Placement

1,300,000

Class D Common Unit [Member]

Subsidiary Sale Of Stock [Line Items]

Distributions Declared, Per Unit

$ 0.18

Class E Common Unit [Member]

Subsidiary Sale Of Stock [Line Items]

Distributions Declared, Per Unit

$ 0.15

Common Class B [Member]

Subsidiary Sale Of Stock [Line Items]

Distributions Declared, Per Unit

$ 0.10

EMH Drop Down [Member] | Affiliated Entity | Midstream Holdings [Member] | EnLink Midstream LP [Member] | Acacia [Member] | EnLink Midstream Holdings, LP

Subsidiary Sale Of Stock [Line Items]

Related Party Transaction, Ownership Interest Transferred

25.00%

25.00%

EMH Drop Down [Member] | Affiliated Entity | Class E Common Unit [Member] [Member] | Midstream Holdings [Member] | EnLink Midstream LP [Member] | Acacia [Member] | EnLink Midstream Holdings, LP

Subsidiary Sale Of Stock [Line Items]

Related Party Transaction, Amounts of Transaction, Shares

36,629,888

EMH Drop Down [Member] | Affiliated Entity | Class D Common Unit [Member] | Midstream Holdings [Member] | EnLink Midstream LP [Member] | Acacia [Member] | EnLink Midstream Holdings, LP

Subsidiary Sale Of Stock [Line Items]

Related Party Transaction, Amounts of Transaction, Shares

31,618,311

Certain Provision of the Part78

Certain Provision of the Partnership Agreement (Allocated Net Income (loss) to the General Partner) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Incentive Distribution Made to Managing Member or General Partner [Line Items]
General Partner share of net income	$ 58	$ 138.3
General Partner Interest
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Income allocation for incentive distributions	47.5	20.6
Unit-based compensation attributable to ENLC’s restricted units	(18.3)	(10.4)
General Partner interest in net income	(6.7)	1.1
General Partners Interest In Asset Drop	$ 35.5	$ 127

Earnings per Unit and Dilutio79

Earnings per Unit and Dilution Computations (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capital Unit [Line Items]
Distribution paid (usd per unit)	$ 0.255	$ 0.255	$ 0.25	$ 0.245	$ 0.235	$ 0.23	$ 0.22	$ 0.18
Enlink Midstream, LLC interest in net income (loss)									$ (357)	$ 90.5	$ 0
Earnings Per Share, Basic	(1.18)	(1.18)	0.09	0.10	0.16	0.18	0.18	0.04	$ (2.17)	$ 0.55	$ 0
Earnings Per Share, Diluted	$ (1.18)	$ (1.18)	$ 0.09	$ 0.10	$ 0.16	$ 0.17	$ 0.18	$ 0.04	$ (2.17)	$ 0.55	$ 0
Distributed Earnings									$ 166.1	$ 127.6
Undistributed Earnings, Basic									(523.1)	$ (37.1)
Class B units
Capital Unit [Line Items]
Distribution paid (usd per unit)										$ 0.05
Common Unit
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income (loss)									(354.5)	$ 89.9
Distributed Earnings									165	126.8
Undistributed Earnings, Basic									(519.5)	(36.9)
Restricted Stock Units (RSUs)
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income (loss)									(2.5)	0.6
Distributed Earnings									1.1	0.8
Undistributed Earnings, Basic									$ (3.6)	$ (0.2)

Earnings per Unit and Dilutio80

Earnings per Unit and Dilution Computations (Unit Weighted Average Schedule) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Capital Unit [Line Items]
Weighted Average Number of Shares Outstanding, Basic	164.2	164
Weighted Average Number Diluted Shares Outstanding Adjustment	0	0.3
Weighted average common shares outstanding: Basic (usd per share)	164.2	164.3
Common Unit
Capital Unit [Line Items]
Weighted Average Number of Shares Outstanding, Basic	164.2	164

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligation	$ 20.6	$ 7.7
Revisions to existing liabilities	(4)	2.2
Liabilities acquired	0	10.2
Accretion expense	0.6	0.5	$ 0.5
Liabilities settled	(3.2)	0
Ending asset retirement obligation	14	20.6	$ 7.7
Asset Retirement Obligation, Current	$ 1.1	$ 8.2

Investment in Unconsolidated 82

Investment in Unconsolidated Affiliate (Details) - USD ($) $ in Millions	Mar. 07, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries		$ 25.8	$ 5.7
Distribution of earnings from unconsolidated affiliates		21.6	7	$ 10.9
Equity in income of equity investment		20.4	18.9	14.8
Investment in equity investments		274.3	270.8
Undistributed Earnings, Basic		523.1	37.1
Gulf Coast Fractionators
Schedule of Equity Method Investments [Line Items]
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries		0	0
Distribution of earnings from unconsolidated affiliates		14.5	11	12
Equity in income of equity investment		13	17.1	$ 14.8
Investment in equity investments		$ 52.6	$ 54.1
Undistributed Earnings, Basic	$ 13.1
Ownership Percentage		38.75%	38.75%	38.75%
Howard Energy Partners
Schedule of Equity Method Investments [Line Items]
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries		$ 25.8	$ 5.7
Distribution of earnings from unconsolidated affiliates		28.2	12.7	$ 0
Equity in income of equity investment		7.4	1.8	0
Investment in equity investments		$ 221.7	$ 216.7
Ownership Percentage		30.60%	30.60%
Total
Schedule of Equity Method Investments [Line Items]
Distribution of earnings from unconsolidated affiliates		$ 42.7	$ 23.7	12
Equity in income of equity investment		$ 20.4	$ 18.9	$ 14.8

Employee Incentive Plans (Expen

Employee Incentive Plans (Expense Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 36.1	$ 22.4	$ 12.8
Amount of related income tax expense recognized in income	8.3	5.3	4.8
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	31.1	16.9	0
Cost of unit-based compensation charged to operating expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	5	2.7	0
Interest of non-controlling partners in unit-based compensation
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	14	8.3	0
Predecessor Equity | General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 2.8	$ 12.8

Employee Incentive Plans (Textu

Employee Incentive Plans (Textuals) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Mar. 07, 2014	Feb. 05, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percent	100.00%
Employer matching contribution, percent of employees' gross pay	6.00%
Employer 401(k) contributions	$ 7	$ 5.5
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized				11,000,000
Vesting Period	3 years
Common Unit | ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized			9,070,000
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$ 16.2
Unrecognized compensation costs, weighted average period for recognition	1 year 7 months
Restricted Stock Units (RSUs) | ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	281,319
Fair value of units vested	$ 8.1	1.9
Restricted Stock Units (RSUs) | ENLK Restricted Unit March Vest [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	128,675
Fair value of units vested	$ 3.4
Restricted Stock Units (RSUs) | ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	273,791
Fair value of units vested	$ 9.8	$ 2.9
Restricted Stock Units (RSUs) | ENLC Restricted Units March Vest [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	102,543
Fair value of units vested	$ 3.4
Maximum [Member] | EnLink Midstream Partners, LP [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Minimum [Member] | EnLink Midstream Partners, LP [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
ENLC [Member] | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$ 16.6
Unrecognized compensation costs, weighted average period for recognition	1 year 7 months
Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$ 3
Unrecognized compensation costs, weighted average period for recognition	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Enlink midstream, LLC [Member] | Maximum [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Enlink midstream, LLC [Member] | Minimum [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
EnLink Midstream Partners, LP [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$ 3
Unrecognized compensation costs, weighted average period for recognition	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0

Employee Incentive Plans (Compe

Employee Incentive Plans (Compensation Schedule) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
ENLK Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units) | shares	1,022,191
Granted (Units) | shares	596,508
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	(281,319)
Forfeited (Units) | shares	(83,651)
Non-vested, end of period (Units) | shares	1,253,729
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 31.25
Granted (usd per share) | $ / shares	26.50
Vested (usd per share) | $ / shares	28.79
Forfeited (usd per share) | $ / shares	30.55
Non-vested, end of period (usd per share) | $ / shares	$ 29.59
Aggregate intrinsic value, end of period (in millions) | $	$ 20.8
Units withheld for payroll taxes on behalf of employees | shares	95,127
ENLC Restricted Units
Weighted Average Grant-Date Fair Value
Units withheld for payroll taxes on behalf of employees | shares	86,635
ENLC Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units) | shares	986,472
Granted (Units) | shares	508,101
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	(273,791)
Forfeited (Units) | shares	(71,889)
Non-vested, end of period (Units) | shares	1,148,893
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 37.03
Granted (usd per share) | $ / shares	31.12
Vested (usd per share) | $ / shares	35.87
Forfeited (usd per share) | $ / shares	35.55
Non-vested, end of period (usd per share) | $ / shares	$ 34.78
Aggregate intrinsic value, end of period (in millions) | $	$ 17.3
EnLink Midstream Partners, LP [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	$ 27.68
Number of Units
Non-vested, beginning of period (Units) | shares	0
Granted (Units) | shares	118,126
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	0
Non-vested, end of period (Units) | shares	118,126
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 0
Granted (usd per share) | $ / shares	35.41
Vested (usd per share) | $ / shares	0
Non-vested, end of period (usd per share) | $ / shares	$ 35.41
Aggregate intrinsic value, end of period (in millions) | $	$ 2
Fair Value Assumptions, Risk Free Interest Rate	0.99%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	33.01%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	5.66%
Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	$ 34.24
Number of Units
Non-vested, beginning of period (Units) | shares	0
Granted (Units) | shares	105,080
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	0
Non-vested, end of period (Units) | shares	105,080
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 0
Granted (usd per share) | $ / shares	40.50
Vested (usd per share) | $ / shares	0
Non-vested, end of period (usd per share) | $ / shares	$ 40.50
Aggregate intrinsic value, end of period (in millions) | $	$ 1.6
Fair Value Assumptions, Risk Free Interest Rate	0.99%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	33.02%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	2.98%

Employee Incentive Plans (Intri

Employee Incentive Plans (Intrinsic and Fair Value of Units Vested) (Details) - Restricted Stock Units (RSUs) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 7.5	$ 1.8
Fair value of units vested	8.1	1.9
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	9.2	3.1
Fair value of units vested	$ 9.8	$ 2.9

Derivatives (Summary of Derivat

Derivatives (Summary of Derivative Income Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives that are not designated for hedge accounting	$ 9.4	$ 22.1	$ 0
Gain on derivative activity	9.4	22.1	$ 0
Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Settlement gain (loss) on derivative	3.6	3.6
Commodity Swap
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives that are not designated for hedge accounting	(7.7)	22.4
Settlement gain (loss) on derivative	17.1	(0.3)
Gain on derivative activity	$ 9.4	$ 22.1

Derivatives (Schedule of Deriva

Derivatives (Schedule of Derivative Assets Liabilities) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Fair value of derivative assets — current	$ 16.8	$ 16.7
Fair value of derivative assets — long term	0	10
Fair value of derivative liabilities — current	(2.9)	(3)
Fair value of derivative liabilities — long term	(0.1)	(2)
Net fair value of derivatives	$ 13.8	$ 21.7

Derivatives (Derivatives Outsta

Derivatives (Derivatives Outstanding) (Details) gal in Millions, bbl in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2015USD ($)bblgalMMBTU	Dec. 31, 2014USD ($)
Short Contracts | Condensate [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	(0.1)
Net fair value of derivatives	$ 0.2
Not Designated as Hedging Instrument
Derivative [Line Items]
Net fair value of derivatives	$ 13.8	$ 21.7
Not Designated as Hedging Instrument | Short Contracts | Liquids
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	(43.9)
Net fair value of derivatives	$ 14.6
Not Designated as Hedging Instrument | Short Contracts | Gas
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	(5.5)
Net fair value of derivatives	$ 1.4
Not Designated as Hedging Instrument | Long Contracts | Liquids
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	(24)
Net fair value of derivatives	$ (2.8)
Not Designated as Hedging Instrument | Long Contracts | Gas
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	(2.9)
Net fair value of derivatives	$ 0.4

Derivatives (Details Textuals)

Derivatives (Details Textuals) $ in Millions	Dec. 31, 2015USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum counterparty loss	$ 16.8
Maximum counterparty loss with netting feature	$ 13.8

Derivatives (Derivatives Other

Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) - Market Approach Valuation Technique $ in Millions	Dec. 31, 2015USD ($)
Derivative [Line Items]
Derivative instruments at fair value	$ 13.8
Less than one year
Derivative [Line Items]
Derivative instruments at fair value	13.9
One to two years
Derivative [Line Items]
Derivative instruments at fair value	(0.1)
More than two years
Derivative [Line Items]
Derivative instruments at fair value	$ 0

Fair Value Measurement (Fair Me

Fair Value Measurement (Fair Measurement on a Recurring Nonrecurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Inputs, Level 2 | Commodity Swap | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Net	$ 13.8	$ 21.7

Fair Value Measurement (Fair Va

Fair Value Measurement (Fair Value of Financial Instrument) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 3,089.8	$ 2,022.5
Carrying (Reported) Amount, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	3,089.8	2,022.5
Obligations under capital lease	16.7	20.3
Estimate of Fair Value, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	2,585.5	2,026.1
Obligations under capital lease	$ 15.6	$ 19.8

Fair Value Measurement (Details

Fair Value Measurement (Details Textuals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 414	$ 237
Long-term Debt	3,089.8	2,022.5
Unsecured Debt	$ 2,675.6	$ 1,785.1
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	2.70%	2.70%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	7.10%	7.10%
Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding		$ 237

Commitments and Contingencies95

Commitments and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense, Net		$ 66.1	$ 51.4	$ 0
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,015		11.7
2,016		9
2,017		13.9
2,018		11
2,019		8.6
Thereafter		72.7
Total Operating Leases		126.9
Gain on litigation settlement	$ 6.1	$ 0	$ 6.1	$ 0

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended				12 Months Ended
		Aug. 31, 2014	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Product sales							$ 3,253.7	$ 2,159.3	$ 179.4
Product sales- affiliates							119.4	505.6	2,116.5
Midstream services							451	253.4	0
Midstream services- affiliates							618.6	567.4	0
Cost of sales	[1]						(3,245.3)	(2,494.5)	(1,736.3)
Operating expenses	[2]						(419.9)	(283.6)	(156.2)
Gain on litigation settlement		$ (6.1)					0	(6.1)	0
Gain (loss) on derivative activity							9.4	22.1	0
Segment profit							786.9	735.8	403.4
Depreciation and amortization							(387.3)	(284.3)	(187)
Impairments			$ (764.2)	$ (799.2)	$ 0	$ 0	(1,563.4)	0	0
Goodwill			2,413.9				2,413.9	3,684.7	401.7
Capital expenditures							570.5	758.7	213.1
Identifiable assets			9,565.1				9,565.1	10,206.7
Texas Operating Segment
Segment Reporting Information [Line Items]
Product sales							320	216.5	129.3
Product sales- affiliates							123.3	348.8	1,419.8
Midstream services							100.2	56.3
Midstream services- affiliates							456.7	410.8
Cost of sales							(412.2)	(456.9)	(1,130.4)
Operating expenses							(181.8)	(146.8)	(121.2)
Gain on litigation settlement								0
Gain (loss) on derivative activity							0	0
Segment profit							406.2	428.7	297.5
Depreciation and amortization							(169.7)	(125.8)	(110.6)
Impairments							(496.3)
Goodwill			703.5				703.5	1,168.2	325.4
Capital expenditures							268	271	147
Identifiable assets			3,709.5				3,709.5	3,302.9
Louisiana Operating Segment
Segment Reporting Information [Line Items]
Product sales							1,527.7	1,612.7	0
Product sales- affiliates							48.5	65.7	0
Midstream services							244.1	153.2
Midstream services- affiliates							20	5.8
Cost of sales							(1,567.6)	(1,674.2)	0
Operating expenses							(105.9)	(64.9)	0
Gain on litigation settlement								(6.1)
Gain (loss) on derivative activity							0	0
Segment profit							166.8	104.4	0
Depreciation and amortization							(109.1)	(69.4)	0
Impairments							(787.3)
Goodwill			0				0	786.8	0
Capital expenditures							59.2	273.1	0
Identifiable assets			2,309.3				2,309.3	3,316.5
Oklahoma Operating Segment
Segment Reporting Information [Line Items]
Product sales							5	13.1	50.1
Product sales- affiliates							13	154.9	696.7
Midstream services							28.3	1.7
Midstream services- affiliates							140.7	149.1
Cost of sales							(17.9)	(142.6)	(605.9)
Operating expenses							(30.3)	(28.7)	(35)
Gain on litigation settlement								0
Gain (loss) on derivative activity							0	0
Segment profit							138.8	147.5	105.9
Depreciation and amortization							(49.8)	(49.4)	(76.4)
Impairments							(0.6)
Goodwill			190.3				190.3	190.3	76.3
Capital expenditures							40.7	17.1	66.1
Identifiable assets			873.4				873.4	892.8
Crude And Condensate Segment
Segment Reporting Information [Line Items]
Product sales							1,401	317	0
Product sales- affiliates							0.8	0.5	0
Midstream services							78.4	42.2
Midstream services- affiliates							18	7.5
Cost of sales							(1,330.6)	(290.9)	0
Operating expenses							(101.9)	(43.2)	0
Gain on litigation settlement								0
Gain (loss) on derivative activity							0	0
Segment profit							65.7	33.1	0
Depreciation and amortization							(51.5)	(37)	0
Impairments							(279.2)
Goodwill			93.2				93.2	112.5	0
Capital expenditures							187.5	183.6	0
Identifiable assets			898				898	871.8
Corporate Segment
Segment Reporting Information [Line Items]
Product sales							0	0	0
Product sales- affiliates							(66.2)	(64.3)	0
Midstream services							0	0
Midstream services- affiliates							(16.8)	(5.8)
Cost of sales							83	70.1	0
Operating expenses							0	0	0
Gain on litigation settlement								0
Gain (loss) on derivative activity							9.4	22.1
Segment profit							9.4	22.1	0
Depreciation and amortization							(7.2)	(2.7)	0
Impairments							0
Goodwill			1,426.9				1,426.9	1,426.9	0
Capital expenditures							15.1	13.9	$ 0
Identifiable assets			$ 1,774.9				$ 1,774.9	$ 1,822.7
[1]	Includes $141.3 million, $354.3 million and $1,588.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate purchased gas.
[2]	Includes $0.5 million, $5.9 million and $36.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate operating expenses from Devon.

Segment Information (Reconcilia

Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting [Abstract]
Segment profits										$ 786.9	$ 735.8	$ 403.4
General and administrative expenses	[1]									(136.9)	(97.3)	(45.1)
Depreciation, Depletion and Amortization, Nonproduction										387.3	284.3	187
Gain (loss) on disposition of assets										(1.2)	0.1	0
Impairments		$ (764.2)	$ (799.2)	$ 0	$ 0					(1,563.4)	0	0
Operating income (loss)		$ (692)	$ (731.8)	$ 71.4	$ 50.5	$ 104.4	$ 87	$ 89.8	$ 73.1	$ (1,301.9)	$ 354.3	$ 171.3
[1]	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.

Quarterly Financial Data (Una98

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 1,066.5	$ 1,170.6	$ 1,274.5	$ 940.5	$ 1,000.2	$ 857.4	$ 927.2	$ 723	$ 4,452.1	$ 3,507.8	$ 2,295.9
Impairments	764.2	799.2	0	0					1,563.4	0	0
Operating income (loss)	(692)	(731.8)	71.4	50.5	104.4	87	89.8	73.1	(1,301.9)	354.3	171.3
Net Income (Loss) Attributable to Noncontrolling Interest	(528.4)	(562.5)	28.4	8	46.2	37.7	35.7	7.1	(1,054.5)	126.7	0
Net income (loss) attributable to Enlink Midstream, LLC	$ (195)	$ (193.4)	$ 16.2	$ 17	$ 29.4	$ 26.5	$ 26.7	$ 41.4	$ (355.2)	$ 124	$ 115.5
Earnings Per Share, Basic	$ (1.18)	$ (1.18)	$ 0.09	$ 0.10	$ 0.16	$ 0.18	$ 0.18	$ 0.04	$ (2.17)	$ 0.55	$ 0
Earnings Per Share, Diluted	$ (1.18)	$ (1.18)	$ 0.09	$ 0.10	$ 0.16	$ 0.17	$ 0.18	$ 0.04	$ (2.17)	$ 0.55	$ 0

Discontinued Operations (Detail

Discontinued Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 07, 2014
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Revenues		$ 6.8	$ 42.1
Revenues - affiliates		10.5	84.6
Total revenues		17.3	126.7
Operating expenses		15.7	130.3
Total operating costs expenses		15.7	130.3
Income (loss) before income taxes		1.6	(3.6)
Income tax provision (benefit)		0.6	(1.3)
Net income (loss)	$ 0	1	(2.3)
Net income attributable to non-controlling interest	0	0	(1.3)
Discontinued operations, net of tax	$ 0	$ 1	$ (3.6)
Gulf Coast Fractionators
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership Percentage	38.75%			38.75%

Supplemental Cash Flow Infor100

Supplemental Cash Flow Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given	$ 180
Common Class C [Member]
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given	$ 180

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Liabilities Disclosure [Abstract]
Interest Payable, Current	$ 23.2	$ 16.9
Employee-related Liabilities, Current	27.7	19.7
Accrued Ad Valorem Taxes	27	23.2
Accrued Capital Expenditures	22.3	22.6
Producer Payments Liability	17	20.3
Other Accruals	57.6	49.6
Other Liabilities, Current	$ 174.8	$ 152.3

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)	Jan. 07, 2016	Dec. 31, 2015	Oct. 29, 2015	Nov. 30, 2014
Subsequent Event [Line Items]
Shares Issued, Price Per Share			$ 17.55	$ 28.37
Common Unit, Issuance Value		$ 14.66
Subsequent Event [Member]
Subsequent Event [Line Items]
Issuance of convertible preferred units in private placement	50,000,000
Shares Issued, Price Per Share	$ 15
Proceeds from Issuance of Convertible Preferred Stock	$ 725,300,000
Common Unit, Issued	15,564,009
Common Unit, Issuance Value	$ 228,200,000
EnLink Midstream LP [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	84.00%
ENLC [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	16.00%
Tall Oak [Member] [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Combination, Consideration Transferred	$ 1,550,000,000
Option to defer final installment	$ 250,000,000
Subsequent Events, Term of Contract	15 years
First Installment [Member] | Tall Oak [Member] [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Combination, Consideration Transferred	$ 1,050,000,000
Proceeds from Issuance of Preferred Limited Partners Units	$ 788,000,000
Common Unit, Issued	15,564,009
Proceeds from Contributions from Parent	$ 19,500,000
Final Installment [Member] | Tall Oak [Member] [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Combination, Consideration Transferred	$ 500,000,000

Condensed Balance Sheets - Pare

Condensed Balance Sheets - Parent Only (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 18	$ 68.4	$ 0	$ 15.6
Accounts receivable	37.5	139
Total current assets	493.7	647.8
Goodwill	2,413.9	3,684.7	401.7
Investment in equity investments	274.3	270.8
Other assets, net	26.5	17.6
Total assets	9,565.1	10,206.7
Other current liabilities	174.8	152.3
Total current liabilities	432.4	484.6
Deferred tax liability	532.1	526.6
Members' equity	2,285.7	2,774.3
Total members' equity	5,424.9	7,074.8	$ 1,783.7	$ 2,002
Total liabilities and members' equity	9,565.1	10,206.7
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	12.1	58.8
Accounts receivable	0.1	0
Accounts Receivable, Related Parties	2.1	2.4
Prepaid expenses and other	9.7	1.1
Total current assets	24	62.3
Goodwill	1,426.9	1,426.9
Investment in equity investments	1,292.9	1,723
Other assets, net	0.8	0.9
Total assets	2,744.6	3,213.1
Other current liabilities	0.4	2.2
Total current liabilities	0.4	2.2
Deferred tax liability	458.5	436.6
Members' equity	2,285.7	2,774.3
Total liabilities and members' equity	$ 2,744.6	$ 3,213.1

Condensed Statement of Operatio

Condensed Statement of Operations - Parent Only (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Equity in income of equity investment										$ 20.4	$ 18.9	$ 14.8
General and administrative expenses	[1]									136.9	97.3	45.1
Total operating costs and expenses	[2]									419.9	283.6	156.2
Operating income (loss)		$ (692)	$ (731.8)	$ 71.4	$ 50.5	$ 104.4	$ 87	$ 89.8	$ 73.1	(1,301.9)	354.3	171.3
Interest and other income										0.8	(0.5)	0
Income (loss) from continuing operations before non-controlling interest and income taxes										(1,384)	326.1	186.1
Income tax provision										(25.7)	(76.4)	(67)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest										$ (1,409.7)	$ 250.7	$ 115.5
Basic common unit (usd per unit)		$ (1.18)	$ (1.18)	$ 0.09	$ 0.10	$ 0.16	$ 0.18	$ 0.18	$ 0.04	$ (2.17)	$ 0.55	$ 0
Earnings Per Share, Diluted		$ (1.18)	$ (1.18)	$ 0.09	$ 0.10	$ 0.16	$ 0.17	$ 0.18	$ 0.04	$ (2.17)	$ 0.55	$ 0
Weighted average common shares outstanding: Basic (usd per share)										164.2	164
Weighted average common shares outstanding: Basic (usd per share)										164.2	164.3
Parent Company
Condensed Financial Statements, Captions [Line Items]
Equity in income of equity investment										$ (325.5)	$ 185.7
General and administrative expenses										4.5	3
Total operating costs and expenses										4.5	3
Operating income (loss)										(330)	182.7
Interest and other income										(0.8)	(2.4)
Income (loss) from continuing operations before non-controlling interest and income taxes										(330.8)	180.3
Income tax provision										(26.2)	(54.3)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest										$ (357)	$ 126
Basic common unit (usd per unit)										$ (2.17)	$ 0.55
Earnings Per Share, Diluted										$ (2.17)	$ 0.55
Weighted average common shares outstanding: Basic (usd per share)										164.2	164
Weighted average common shares outstanding: Basic (usd per share)										164.2	164.3
[1]	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.
[2]	Includes $0.5 million, $5.9 million and $36.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate operating expenses from Devon.

Condensed Statement of Cash Flo

Condensed Statement of Cash Flows - Parent Only (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (1,409.7)	$ 250.7	$ 115.5
Adjustments to reconcile net income (loss) to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Equity in income of equity investment	(20.4)	(18.9)	(14.8)
Deferred tax expense	22.6	67.4	35.5
Share-based Compensation	36.1	19.6	0
Amortization of debt issue cost	3.3	1.9	0
Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other	197.5	(98.9)	0
Accounts payable, and other accrued liabilities	(171.4)	(16.9)	(8.6)
Net cash provided by operating activities	628.4	458.9	330.3
Cash flows from investing activities:
Payments to Acquire Other Productive Assets	524.2	357.9	0
Distribution from unconsolidated affiliates in excess of earnings	21.1	10.9	1.1
Acquisition of business	(25.8)	(5.7)	0
Net cash used in investing activities	(1,097.3)	(1,148.6)	(243.2)
Cash flows from financing activities:
Proceeds from borrowings	3,204.4	3,367.8	0
Payments on borrowings	(2,134.3)	(2,792.7)	0
Debt refinancing cost	(9.6)	(19.7)	0
Conversion of restricted units, net of units withheld for taxes	(2.9)	(1.1)	0
Distribution to members	(162.8)	(89)	0
Net cash provided by (used in) financing activities	418.5	758.1	(151.2)
Net increase (decrease) in cash and cash equivalents	(50.4)	68.4	(15.6)
Cash and cash equivalents, beginning of year	68.4	0	15.6
Cash and cash equivalents, end of year	18	68.4	0
Parent Company
Cash flows from operating activities:
Net income (loss)	(357)	126
Adjustments to reconcile net income (loss) to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Equity in income of equity investment	325.5	(185.7)
Deferred tax expense	23.9	52
Share-based Compensation	0.4	0.2
Amortization of debt issue cost	0.3	0.2
Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other	(8.5)	(1.5)
Accounts payable, and other accrued liabilities	(1.8)	(13.5)
Net cash provided by operating activities	(17.2)	(22.3)
Cash flows from investing activities:
Proceeds from sale of investment	0	163
Payments to Acquire Other Productive Assets	0	16.7
Distribution from unconsolidated affiliates in excess of earnings	186.3	194.9
Acquisition of non-controlling interest	0	(93.5)
Acquisition of business	(50)	0
Net cash used in investing activities	136.3	247.7
Cash flows from financing activities:
Proceeds from borrowings	0	216.3
Payments on borrowings	0	(291.5)
Debt refinancing cost	(0.1)	(1.1)
Conversion of restricted units, net of units withheld for taxes	(2.9)	(1.3)
Distribution to members	(162.8)	(89)
Net cash provided by (used in) financing activities	(165.8)	(166.6)
Net increase (decrease) in cash and cash equivalents	(46.7)	58.8
Cash and cash equivalents, beginning of year	58.8
Cash and cash equivalents, end of year	12.1	58.8
Loss from issuance of Partnership units	(13.7)	1.8
Cash Equivalents, at Carrying Value	$ 12.1	$ 58.8	$ 0