EnLink Midstream (ENLC) 10-K20 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 11, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Amendment Flag	FALSE
Entity Registrant Name	Enlink Midstream, LLC
Entity Central Index Key	1592000
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		164,141,435
Entity Public Float			$1.90
Common unit price			$41.66

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$68.40	$0
Accounts receivable:
Trade, net of allowance for bad debt	139	0.4
Accrued revenues and other	253.3	0
Related party	120.8	0
Fair value of derivative assets	16.7	0
Natural gas and natural gas liquids inventory, prepaid expenses and other	48.7	5.8
Assets held for disposition	0	72.7
Total current assets	646.9	78.9
Property and equipment, net of accumulated depreciation of $1,422.3 and $1,169.8, respectively	4,934.30	1,768.10
Intangible assets, net of accumulated amortization of $36.5	533	0
Goodwill	3,684.70	401.7
Fair value of derivative assets	10	0
Investments in unconsolidated affiliates	270.8	61.1
Other assets, net	17.6	0
Total assets	10,097.30	2,309.80
Current Liabilities:
Drafts payable	13.2	0
Accounts payable	108.5	1.7
Accounts payable to related party	3	0
Accrued gas, condensate and crude oil purchases	204.5	0
Contract liability	20.3	0
Accrued capital expenditures	18.9	0
Fair value of derivative liabilities	3	0
Accrued interest	16.9	0
Other current liabilities	92.1	38.8
Liabilities held for disposition	0	37
Total current liabilities	480.4	77.5
Long-term debt	2,022.50	0
Asset retirement obligations	10.9	7.7
Other long-term liabilities	83.8	0
Deferred tax liability	526.6	440.9
Fair value of derivative liabilities	2	0
Members' equity:
Predecessor	0	1,783.70
Members' equity (164,055,004 units issued and outstanding at December 31, 2014)	2,774.30	0
Non-controlling interest	4,196.80	0
Total members' equity	6,971.10	1,783.70
Commitments and contingencies (Note 14)
Total liabilities and members' equity	$10,097.30	$2,309.80

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Accumulated amortization of intangible assets	$36.50	$0
Stockholders' Equity Attributable to Parent [Abstract]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$1,422.30	$1,169.80
Common Unitholders	164,055,004	0

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues:
Revenues	$2,412.70		$179.40		$153.90
Revenues - affiliates	1,065.60		2,116.50		1,753.90
Gain on derivatives	22.1		0		0
Total revenues	3,500.40		2,295.90		1,907.80
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil	2,494.50	[1]	1,736.30	[1]	1,428.10	[1]
Operating expenses	278.2	[2]	156.2	[2]	149.9	[2]
General and administrative	97.3	[3]	45.1	[3]	41.7	[3]
Depreciation and amortization	280.3		187		145.4
Gain on sale of property	-0.1		0		0
Impairments	0		0		16.4
Gain on litigation settlement	-6.1		0		0
Total operating costs and expenses	3,144.10		2,124.60		1,781.50
Operating income	356.3		171.3		126.3
Other income (expense):
Interest expense, net of interest income	-49.8		0		0
Equity in income of equity investment	18.9		14.8		2
Gain on extinguishment of debt	3.2		0		0
Other expense	-0.5		0		0
Total other income (expense)	-28.2		14.8		2
Income from continuing operations before non-controlling interest and income taxes	328.1		186.1		128.3
Income tax provision	-76.4		-67		-46.2
Net income from continuing operations	251.7		119.1		82.1
Income (loss) from discontinued operations, net of tax	1		-2.3		-5.2
Income from discontinued operations attributable to non-controlling interest, net of tax	0		-1.3		-1.1
Discontinued operations, net of tax	1		-3.6		-6.3
Net income	252.7		115.5		75.8
Net income attributable to the non-controlling interest	126.7		0		0
Net income attributable to Enlink Midstream, LLC	126		115.5		75.8
Predecessor interest in net income (4)	35.5	[4]	0	[4]	0	[4]
Enlink Midstream, LLC interest in net income	$90.50		$0		$0
Net income attributable to Enlink Midstream Partners, LP per limited partners' unit:
Basic common unit (usd per unit)	$0.55		$0		$0
Diluted common unit (usd per unit)	$0.55		$0		$0

[1]	Includes $354.3 million, $1,588.2 million and $1,310.3 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate purchased gas.
[2]	Includes $5.9 million, $36.2 million and $33.8 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate operating expenses.
[3]	Includes $11.6 million, $45.1 million and $41.7 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate general and administrative expenses.
[4]	Represents net income attributable to the Predecessor for the periods prior to March 7, 2014.

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Operations (parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Purchased gas, NGLs, condensate and crude oil	$2,494.50	[1]	$1,736.30	[1]	$1,428.10	[1]
General and administrative	97.3	[2]	45.1	[2]	41.7	[2]
Affiliated Entity
Purchased gas, NGLs, condensate and crude oil	354.3		1,588.20		1,310.30
Operating expenses - affiliates	5.9		36.2		33.8
General and administrative	$11.60		$45.10		$41.70

[1]	Includes $354.3 million, $1,588.2 million and $1,310.3 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate purchased gas.
[2]	Includes $11.6 million, $45.1 million and $41.7 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate general and administrative expenses.

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Partners' Equity (USD $)	Total	Predecessor Equity	Common Units	Non- Controlling Interest
In Millions, unless otherwise specified	Total	Predecessor Equity	Common Units	Non- Controlling Interest
Balance at the beginning of the period at Dec. 31, 2011	$1,901.30	$1,856	$0	$45.30
Increase (Decrease) in Partners' Capital
Distributions from the Predecessor	21.5	21.5	0	0
Distributions from non-controlling interest	3.4	0	0	3.4
Net income	75.8	75.8	0	0
Balance at the end of the period at Dec. 31, 2012	2,002	1,953.30	0	48.7
Increase (Decrease) in Partners' Capital
Distributions from the Predecessor	-285.1	-285.1	0	0
Distributions from non-controlling interest	-1.6	0	0	-1.6
Sale of non-controlling interest	-47.1			-47.1
Net income	115.5	115.5	0	0
Balance at the end of the period at Dec. 31, 2013	1,783.70	1,783.70	0	0
Increase (Decrease) in Partners' Capital
Distributions from the Predecessor	-71.9	-71.9	0	0
Distributions from non-controlling interest	-204.3		0	-204.3
Issuance of units for reorganization of predecessor equity	0	-1,747.30	941.7	805.6
Issuance of units for reorganization of predecessor equity (Units)			115.5
Issuance of common units for acquisition of Company	4,670.30		1,822.60	2,847.70
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	0		204.9
Issuance of units by the Partnership	412	0	0	412
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Issuance of Equity by Subsidiary to Noncontrolling Interests	0.7	0	-1.1	1.8
Conversion of restricted units for common units, net of units withheld for taxes	-1.1	0	-1.2	0.1
Non-controlling partner's impact on conversion of restricted units and options	-0.3	0	0	-0.3
Conversion of restricted units for common units, net of units withheld for taxes (Units)			0.1
Unit-based compensation	19.6	0	10.6	9
Dividends, Common Stock, Cash	-89	0	-89	0
Purchase of non-controlling interest	-12.5			-12.7
Non-controlling interest contributions	6.3		0.2	6.3
Net income	252.7	35.5	90.5	126.7
Balance at the end of the period at Dec. 31, 2014	$6,971.10	$0	$2,774.30	$4,196.80
Balance at the end of the period (Units) at Dec. 31, 2014			164.1

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income from continuing operations	$251.70	$119.10	$82.10
Adjustments to reconcile net income to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Depreciation and amortization	280.3	187	145.4
Asset impairments	0	0	16.4
Accretion expense	0.5	0.5	0.4
Gain on extinguishment of debt	-3.2	0	0
Gain on sale of property and other assets	-0.1	0	0
Non-cash unit-based compensation	19.6	0	0
Deferred tax expense (benefit)	67.4	35.5	-12.9
Gain on derivatives recognized in net income	-22.1	0	0
Cash settlements on derivatives	-0.3	0	0
Amortization of debt issue costs	1.9	0	0
Amortization of premium on notes	-2.9	0	0
Distribution of earnings from equity investments	7	10.9	0.4
Equity in income of equity investments	-18.9	-14.8	-2
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	-98.1	0	0
Natural gas and natural gas liquids, prepaid expenses and other	-8.2	0.7	-2.6
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	-17.3	-8.6	-17.5
Net cash provided by operating activities	457.3	330.3	209.7
Cash flows from investing activities:
Additions to property and equipment	-763.6	-244.3	-337.2
Acquisition of business	-283	0	0
Proceeds from sale of property	0.1	0	0
Investment in limited liability company	-5.7	0	-17.1
Distribution from limited liability company in excess of earnings	10.9	1.1	1.9
Net cash used in investing activities	-1,041.30	-243.2	-352.4
Cash flows from financing activities:
Proceeds from borrowings	3,367.80	0	0
Payments on borrowings	-2,792.70	0	0
Payments on capital lease obligations	-3	0	0
Increase in drafts payable	10.2	0	-1.6
Debt refinancing costs	-19.7	0	0
Conversion of restricted units, net of units withheld for taxes	-1.1	0	0
Conversion of Partnership's restricted units, net of units withheld for taxes	-0.7	0	0
Proceeds from issuance of Partnership common units	412	0	0
Distributions to non-controlling interest	-204.3	0	0
Contributions by non-controlling interest	6.3	0	0
Distribution to members	89	0	0
Contributions by (distributions to) Predecessor	-21.3	-151.2	87.8
Proceeds from exercise of Partnership unit options	0.4	0	0
Purchase of non-controlling interest	-12.5	0	0
Net cash provided by (used in) financing activities	652.4	-151.2	86.2
Net cash provided by operating activities	5	31.1	66.9
Net cash provided by (used in) investing activities	-0.6	154.2	61
Net cash used in financing activities-net distributions to Devon and non-controlling interests	-4.4	-136.8	-63.9
Net cash provided by discontinued operations	0	48.5	64
Net increase (decrease) in cash and cash equivalents	68.4	-15.6	7.5
Cash and cash equivalents, beginning of period	0	15.6	8.1
Cash and cash equivalents, end of period	68.4	0	15.6
Cash paid for interest	55.8	0	0
Cash paid for income taxes	$7.50	$0	$0

Organization_and_Summary_of_Si

Organization and Summary of Significant Agreement	12 Months Ended
	Dec. 31, 2014
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 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. (“New 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 7.1% limited partner interest in EnLink Midstream LP ( the "Partnership") as of December 31, 2014 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). New Acacia directly owns a 50% limited partner interest in Midstream Holdings. Midstream Holdings formerly was a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 Class B Units (“Class B Units”) to a wholly-owned subsidiary of Devon, which represents approximately 70% of the outstanding limited liability company interests in ENLC. The Class B units converted to common units on May 6, 2014.
	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.”
	Our assets consist of equity interests in the Partnership and Midstream Holding. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing, fractionation 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. Midstream Holdings is a partnership held by us and the Partnership and is engaged in the gathering, transmission and processing of natural gas. As of December 31, 2014, our interests in the Partnership and Midstream Holdings consist of the following:

	•	17,431,152 common units representing an aggregate 7.1% limited partner interest in the Partnership;

	•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest and all of the incentive distribution rights in the Partnership; and

	•	50% limited partner interest in Midstream Holdings and 25% limited partner interest in Midstream Holdings as of February 17, 2015.
	(b) Nature of Business
	The Company primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing, to producers of natural gas, NGLs, crude oil and condensate. The Company 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 Company 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 Company operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Company provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Company also has crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to the premium markets in this area. The Company'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 Company'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 Company also has transmission lines that transport NGLs from east Texas and from its south Louisiana processing plants to its fractionators in south Louisiana. The Company'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 Company's processing plants remove NGLs and CO2 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_Policie

Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

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 and are reflected in the balance sheet as of December 31, 2013 as the Predecessor. 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. 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. All significant intercompany transactions and balances have been eliminated.

Prior year balances have been prepared from records maintained by Devon and may not be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as Predecessor equity, in lieu of owner’s equity, in the consolidated financial statements.

During the prior year reporting periods for the accompanying financial statements, Devon provided cash management services to the Predecessor through a centralized treasury system. As a result, all revenues covered by the centralized treasury system were deemed to have been received in cash by the Predecessor from Devon during the period in which the revenue was recorded in the financial statements. All charges and cost allocations covered by the centralized treasury system were deemed to have been paid in cash to Devon during the period in which the cost was recorded in the financial statements. The net effects of these amounts are reflected as net distributions to or contributions from Devon and non-controlling interests in the accompanying statements of equity. As a result of this accounting treatment, the Predecessor’s working capital does not reflect any affiliate accounts receivables or payables, except for amounts that pertain to planned cash transfers between the Predecessor and Devon affiliates.

(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.

The Company recognizes revenue for sales or services at the time the natural gas, NGLs, condensate or crude oil are delivered or at the time the service is performed at a fixed or determinable price. The Company 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. The Company's purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) 605-45-45-1. Except for fee based arrangements, the Company acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk.

The Company 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 $1.5 million at December 31, 2014, which approximate the fair value of these imbalances. The Company had imbalance receivables of $1.2 million at December 31, 2014, which are carried at the lower of cost or market value. There were no imbalance payables or receivables at December 31, 2013.

(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 Company's inventories of products consist of natural gas, NGLs, crude oil and condensate. The Company 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):

December 31,

2014

2013

Transmission assets

1,270.30

95.9

Gathering systems

2,391.90

1,617.80

Gas processing plants

2,356.10

1,223.70

Other property and equipment

104

0.5

Construction in process

234.3

—

Property, plant and equipment

6,356.60

2,937.90

Accumulated depreciation and amortization

(1,422.3

)

(1,169.8

)

Property, plant and equipment, net

4,934.30

1,768.10

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 is a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method will be 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 $243.8 million, $187.0 million and $145.4 million was recorded for the years ended December 31, 2014, 2013 and 2012, 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.

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 2012, the Predecessor recognized $16.4 million of asset impairment related to its continuing operations. The impairment resulted from the impact of lower natural gas and NGL prices on the Predecessor’s Northridge system and is included in the Oklahoma segment.

(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, equity 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 equity 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 31st, 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. The 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 with 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 the reporting unit to 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. The Company or Predecessor performed annual impairment tests of goodwill as of the fourth quarters of 2014, 2013 and 2012. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of the Company’s goodwill, by assigned reporting unit.

December 31,

2014

2013

(in millions)

Texas

1,168.20

325.4

Louisiana

786.8

—

Oklahoma

190.3

76.3

Ohio River Valley

112.5

—

Corporate

1,426.90

—

Total

3,684.70

401.7

The increase to the Company's goodwill in 2014 of $3.3 billion represents the goodwill recognized on the business combination with Midstream Holdings described in Note 3.

(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.

The following table represents the Partnership's total purchased intangible assets at years ended December 31, 2014 (in millions):

Gross

Accumulated

Net

Carrying

Amortization

Carrying

Amount

Customer relationships

569.5

(36.5

)

533

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $36.5 million for the year ended December 31, 2014.

The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions):

2015

44.5

2016

44.5

2017

44.5

2018

44.5

2019

43.6

Thereafter

311.4

Total

533

(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. The Company provided an asset retirement obligation of $19.1 million and $7.7 million as of December 31, 2014 and 2013, respectively. $8.2 million of the provided asset retirement obligation as of December 31, 2014 is reflected in Other Current Liabilities.

(l) Other Long-Term Liabilities

Included in other current and long-term liabilities is an $80.7 million total liability related to an onerous performance obligation assumed in the business combination. 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 Partnership 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 no reserve for uncollectible receivables as of December 31, 2014 and 2013.

During the year ended December 31, 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 11.0%, of the consolidated revenues for the year ended December 31, 2014. The affiliate transactions with Devon represented 30.4%, 92.2% and 91.9% of the consolidated midstream revenues for the years ended December 31, 2014, 2013 and 2012, 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. For the year ended December 31, 2014, 2013 and 2012 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) Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements and Property, Plant and Equipment, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2014, limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have, or will have, a major effect on operations and financial results. The amendment requires expanded disclosures for discontinued operations and also requires additional disclosures regarding disposals of individually significant components that do not qualify as discontinued operations. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. This amendment has no impact on our current disclosures, but will in the future if we dispose of any individually significant components.

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 US 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 also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity'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, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the year ended December 31, 2014, and have determined that none would have a material impact on our Consolidated Financial Statements.

(t) 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 $17.5 million as of December 31, 2014 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.

(u) 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.

Acquisition

Acquisition	12 Months Ended
	Dec. 31, 2014
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Acquisition	Acquisition
	Chevron acquisition
	Effective November 1, 2014, the Partnership acquired, through one of its wholly owned subsidiaries, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $234.0 million in cash, subject to certain adjustments. 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 Partnership paid cash of $231.5 million in November 2014 in cash.
	The following table is a preliminary summary of the fair value of the assets acquired and liabilities assumed:


	Purchase Price Allocation (in millions):
	Assets acquired:
	Property, plant and equipment		$	242.2

	Liabilities assumed:
	Current liabilities		(10.7		)
	Total purchase price		$	231.5

	The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. For the period from November 1, 2014 to December 31, 2014, the Company recognized $5.3 million of revenues and $4.9 million of operating expenses related to the assets acquired.
	E2 Investment and Drop Down to Partnership
	On October 22, 2014, the Partnership acquired equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) from EMI. The total consideration for the transaction is approximately $194.0 million, including a cash payment of $163.0 million and 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). This acquisition has been accounted for as an acquisition under common control under ASC 805.
	On October 10, 2014, the Company purchased 100% of Class A units and 50% of Class B Units owned by E2 management in E2 Appalachian Compression, LLC for $7.0 million and $5.5 million, respectively.
	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.
	The following table summarizes the purchase price (in millions, except per unit price):


	EMI outstanding common shares:
	Held by public shareholders	48

	Restricted shares	0.4

	Total subject to exchange	48.4

	Exchange ratio	1			x

	Exchanged shares	48.4

	EMI common share price(1)	$	37.6

	EMI consideration	$	1,822.60

	Fair value of non-controlling interests in E2	18.9

	Total consideration and fair value of non-controlling interests	$	1,841.50

	Partnership outstanding units:
	Common units held by public unitholders	75.1

	Preferred units held by third party (2)	17.1

	Restricted units	0.4

	Total	92.6

	Partnership common unit price(3)	$	30.51

	Partnership common units value	$	2,825.20

	Partnership outstanding unit options value	$	3.9

	Total fair value of non-controlling interests in the Partnership(3)	$	2,828.80

	Total consideration and fair value of non-controlling interests	$	4,670.30

(1) The final purchase price is based on the fair value of the Company's common shares as of the closing date, March 7, 2014.
(2) The Partnership converted the preferred units to common units in February 2014.
(3) The final purchase price is based on the fair value of the Partnership's common units as of the closing date, March 7, 2014.
The following table is a summary of the fair value of the assets acquired and liabilities assumed from EMI in the business combination as of March 7, 2014:


Purchase Price Allocation (in millions):
Assets acquired:
Current assets	$	437.4

Property, plant and equipment	2,437.90

Intangibles assets	569.4

Equity investment	221.5

Goodwill	3,283.10

Other long term assets	1.3

Liabilities assumed:
Current liabilities	(515.0		)
Long-term debt	(1,453.7		)
Deferred taxes	(210.4		)
Other long term liabilities	(101.2		)
Total purchase price	$	4,670.30

Goodwill recognized from the business combination primarily relates to the value created from additional growth opportunities and greater operating leverage in the Company's core areas. The goodwill is allocated among our Texas, Louisiana, Oklahoma, and ORV segments. All of the goodwill is non-deductible for tax purposes.
For the period from March 7, 2014 to December 31, 2014, the Company recognized $2,504.4 million of revenues and $2,460.6 million of operating expenses related to the assets acquired in the business combination.
Unaudited Pro Forma Information
The following unaudited pro forma condensed financial data for the year ended December 31, 2014 and 2013 gives effect to the business combination, Chevron acquisition and E2 drop down as if they had occurred on January 1, 2013. The 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. As of March 7, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 4. Pro forma financial information associated with the business combination and with these agreements with Devon is reflected below.


		Year Ended December 31,
		2014				2013
		(in millions except for per unit data)
Pro forma total revenues		$	3,698.20			$	2,597.90

Pro forma net income		$	240.1			$	102.4

Pro forma net income attributable to Enlink Midstream, LLC		$	67.5			$	70.4

Pro forma net income per common unit:
Basic		$	0.41			$	0.43

Diluted		$	0.41			$	0.43

Affiliate_Transactions

Affiliate Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Affiliate Transactions
	The Partnership engages in various transactions with Devon and other affiliated entities. Prior to March 7, 2014, these 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. 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.
	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 economic burdens and benefits of Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination. Assets that were not contributed from the Predecessor are reflected as discontinued operations prior to March 7, 2014 and reflected as a reduction in equity at March 7, 2014. Further, the Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. As a result of the business combination, Midstream Holdings is a legal entity that is treated as a partnership for tax purposes and is not subject to U.S. federal income tax or certain state income taxes in the future. The business combination transactions were treated as a reorganization under common control for tax purposes. Therefore, the elimination of the related deferred tax liability is reflected as an increase in equity.
	Midstream Holdings, in which the Partnership holds a 50% economic interest as of March 7, 2014, conducts business with Devon pursuant to the gathering and processing agreements described below. The legacy Partnership also historically has maintained a relationship with Devon as a customer, as described in more detail below.
	Gathering and Processing Agreements
	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. 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. 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 system 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, 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.
	On August 29, 2014, Gas Services assigned its 10-year gathering and processing agreement 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. Such assignment was effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, Linn Energy is responsible to perform Gas Services' obligations under the agreement, which remains in full force and effect. The assignment of this agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma. Gross operating margin related to our Northridge assets totaled $28.4 million for the year ended December 31, 2014.
	Historical Customer Relationship with Devon
	As noted above, the Partnership maintained a customer relationship with Devon prior to the business combination pursuant to which certain of the Partnership's subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with such Devon subsidiaries. The terms of these agreements vary, but the agreements expire between March 2015 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, one of the Partnership's subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership's subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee. These NGL purchase and sale agreements have month-to-month terms.
	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, including IT, accounting, pipeline integrity, compliance management and procurement services, and the Partnership provides certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. Substantially all services under the transition services agreement were completed during 2014.
	GCF Agreement
	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 Devon agreed, from and after the closing of the business combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% interest in GCF, which owns a fractionation facility in Mont Belvieu, Texas.
	Lone Camp Gas Storage Agreement
	In connection with the closing of the business combination, Midstream Holdings entered into an agreement with Gas Services under which Midstream Holdings provides gas storage services at its Lone Camp storage facility. Under this agreement, Gas Services reimburses Midstream Holdings for the expenses it incurs in providing the storage services. This agreement has minimal to no impact on Midstream Holdings' annual revenue.
	Acacia Transportation Agreement
	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.
	Office Leases
	In connection with the closing of the business combination, the Operating Partnership entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which the Operating Partnership leases office space from Devon at its Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.
	Tax Sharing Agreement
	In connection with the closing of the business combination, the Partnership, ENLC and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due.

	The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which were settled through an adjustment to equity prior to March 7, 2014 (in millions):


			Year Ended December 31,
			2014				2013				2012
	Continuing Operations:
	Operating revenues - affiliates		$	(436.4	)		$	(2,116.5	)		$	(1,753.9	)
	Operating expenses - affiliates		340				1,669.50				1,385.80

	Net affiliate transactions		(96.4		)		(447.0		)		(368.1		)
	Capital expenditures		16.2				244.3				337.2

	Other third-party transactions, net		58.9				51.5				118.7

	Net third-party transactions		75.1				295.8				455.9

	Net cash distributions to Devon - continuing operations		(21.3		)		(151.2		)		87.8

	Non-cash distribution of net assets to Devon		(6.3		)		—				—

	Total net distributions per equity		$	(27.6	)		$	(151.2	)		$	87.8


	Discontinued operations:
	Operating revenues - affiliates		$	(10.4	)		$	(84.6	)		$	(152.0	)
	Operating expenses - affiliates		5				32.7				86.3

	Cash used in financing activities - affiliates		—				(5.6		)		(1.1		)

	Net affiliate transactions		(5.4		)		(57.5		)		(66.8		)
	Capital expenditures		0.6				1.1				26.5

	Other third-party transactions, net		0.4				(72.0		)		(23.6		)

	Net third-party transactions		1				(70.9		)		2.9

	Net distributions to Devon and non-controlling interests - discontinued operations		(4.4		)		(128.4		)		(63.9		)
	Non-cash distribution of net assets to Devon		(39.9		)		—				—

	Total net distributions per equity		$	(44.3	)		$	(128.4	)		$	(63.9	)
Total distributions- continuing and discontinued operations		$	(71.9	)		$	(279.6	)		$	23.9

For the years ended December 31, 2014, 2013, 2012, Devon was a significant customer to the Partnership. Devon accounted for 30.4%, 92.2% and 91.9% of the Partnership's revenues for the year ended December 31, 2014, 2013 and 2012, respectively. The affiliate revenues after March 7, 2014 through December 31, 2014 were $629.2 million. The Partnership had an accounts receivable balance related to transactions with Devon of $120.8 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $3.0 million as of December 31, 2014.
Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the year ended December 31, 2014 and $12.8 million for both 2013 and 2012. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million, $8.7 million and $9.1 million for the year ended December 31, 2014, 2013 and 2012 respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

LongTerm_Debt

Long-Term Debt	12 Months Ended
Long-Term Debt	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt
	As of December 31, 2014, long-term debt consisted of the following (in millions):


			2014
	Partnership credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at December 31, 2014 was 1.9%		$	237
			$	237
	Company bank credit facility (due 2019)		—
	Company bank credit facility (due 2019)		—
	The Partnership's senior unsecured notes (due 2019), net of discount of $0.5 million, which bear interest at the rate of 2.70%		399.5
			399.5
	The Partnership's senior unsecured notes (due 2022), including a premium of $21.9 million, which bear interest at the rate of 7.125%		184.4
			184.4
	The Partnership's senior unsecured notes (due 2024), including a premium of $3.2 million, which bear interest at the rate of 4.40%		553.2
			553.2
	The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million, which bear interest at the rate of 5.60%		349.7
			349.7
	The Partnership's senior unsecured notes (due 2045), net of discount of $1.7 million, which bear interest at the rate of 5.05%		298.3
			298.3
	Other debt		0.4
	Other debt		0.4
	Debt classified as long-term		$	2,022.50
	Debt classified as long-term		$	2,022.50
	Maturities. Maturities for the long-term debt as of December 31, 2014 are as follows (in millions):


	2015	$	0.2
	2015	$	0.2
	2016	0.1
	2016	0.1
	2017	0.1
	2017	0.1
	2018	—
	2018	—
	2019	637
	2019	637
	Thereafter	1,362.40
	Thereafter	1,362.40
	Subtotal	1,999.80
	Subtotal	1,999.80
	Less: premium (discount)	22.7
	Less: premium (discount)	22.7
	Total outstanding debt	$	2,022.50
	Total outstanding debt	$	2,022.50
	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”). The Company used borrowings under the credit facility to repay outstanding borrowings under the margin loan facility of XTXI Capital, LLC (a former wholly-owned subsidiary of EnLink Midstream, Inc.), which was paid in full and terminated on March 7, 2014. Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 17,431,152 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, (iii) the limited partner interest in Midstream Holdings held by us and (iv) 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 0.50%, 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. The Company expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months.
	As of December 31, 2014, 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 new $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). The Partnership credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless the Partnership requests, and the requisite lenders agree, to extend it pursuant to its terms. 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 maximum allowed ratio of consolidated indebtedness to consolidated EBITDA may increase 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. The applicable margins vary depending on the Partnership’s credit rating. Upon breach by the Partnership of certain covenants governing the Partnership credit facility, amounts outstanding under the Partnership credit facility, if any, may become due and payable immediately. The Partnership expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months.
	As of December 31, 2014, there were $13.9 million in outstanding letters of credit and $237.0 million in outstanding borrowings under the Partnership credit facility, leaving approximately $749.1 million available for future borrowing based on the borrowing capacity of $1.0 billion.


	Pricing Level		Debt Ratings		Applicable Rate Commitment Fee	EuroDollar Rate/Letter of Credit	Base Rate +
	1		A-/A3 or better		0.10%	1.00%	—%
	2		BBB+/Baa1		0.13%	1.13%	0.13%
	3		BBB/Baa2		0.18%	1.25%	0.25%
	4		BBB-/Baa3		0.22%	1.50%	0.50%
	5		BB+/Ba1		0.27%	1.63%	0.63%
	6		BB/Ba2 or worse		0.35%	1.75%	0.75%
	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 “Initial 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 $100.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “2024 Notes”) and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045, at prices to the public of 104.007% and 99.452%, respectively, of their face value. The 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 and the notes issued on March 19, 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.
Prior to June 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 100.000% 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 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;


•	our default under other indebtedness that exceeds a certain threshold amount;


•	failure by us to pay final judgments that exceed a certain threshold amount; 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.
Other Borrowings. On December 31, 2014, E2 Energy Services LLC (“E2 Services”), one of the Ohio services companies in which the Partnership invests had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.4 million due in increments through July 2017. The notes bear interest at fixed rates ranging 3.9% to 7.0%.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	All taxes presented prior to March 7, 2014, the transaction date, relate to the predecessor’s results of continuing operations. Taxes presented for the period subsequent to March 6, 2014 relate to the combined operations of ENLC, Predecessor and the remaining underlying operating entities.
	ENLC will file a consolidated federal income tax return, which will include the results of operations on its two underlying corporate subsidiaries. Income taxes are calculated based on each entity’s separate taxable income or loss.
	Components of income tax from continuing operations are as follows (in millions):


		Years Ended December 31,
		2014			2013			2012
	Current income tax expense
	Current tax expense	$	9		$	31.5		$	59.1

	Deferred tax expense	67.4			35.5			(12.9		)

	Total income tax expense	$	76.4		$	67		$	46.2

	The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income from continuing operations before income taxes (in millions):


		Years Ended December 31,
		2014			2013			2012
	Expected income tax expense based on federal statutory rate of 35%	$	70.7		$	65.1		$	44.6

	State income taxes, net of federal benefit and other	5.7			1.9			1.6

	Total income tax expense	$	76.4		$	67		$	46.2

	Deferred Tax Assets and Liabilities
	The tax effects of temporary differences that gave rise to significant portions of the Predecessor’s deferred tax assets and liabilities are presented below (in millions):


		Years Ended December 31,
		2014			2013
	Deferred income tax assets:
	Asset retirement obligations	$	2		$	2.8

	State net operating loss carryforward, non current	4.2			—

	Federal net operating loss carryforward, current	16.9			0.4

	Total deferred tax assets	23.1			3.2

	Deferred tax liabilities:
	Property, plant, equipment, and intangible assets, non current	(523.5		)	(444.1		)
	Other	(9.3		)	—

	Total deferred tax liabilities	(532.8		)	(444.1		)
	Deferred tax liability, net	$	(509.7	)	$	(440.9	)
	As a result of the merger transaction, predecessor acquired various federal and state net operating loss carryforwards. Federal carryforwards totaled $146.3 million of which $98.1 million was utilized in 2014. The remaining carryforward of $48.2 million is expected to be utilized in 2015.
	State net operating loss carryforwards totaling $85.5 million were also acquired on the transaction date. Additional state loss carryforwards totaling $11.9 million were generated in 2014. The balance at December 31, 2014 is approximately $97.4 million. These carryforwards, representing a net deferred tax asset of $4.2 million as of December 31, 2014, will begin expiring in 2023 through 2029. 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.
	A reconciliation of the beginning and ending amount of the unrecognized tax benefits is as follows (in millions):


	Balance as of December 31, 2013	$	—

	Unrecognized tax positions assumed in merger	3.8

	Decrease due to prior year tax positions	(2.0		)
	Increases due to current year tax positions	0.2

	Balance as of December 31, 2014	$	2

	The $2.0 million decrease due to prior year tax positions mainly consists of unrecognized tax benefits assumed in the merger that expired in 2014. Unrecognized tax benefits as of December 31, 2014 of $2.0 million, if recognized, would affect the effective tax rate. It is unknown when the remaining uncertain tax position will be resolved.
	Per Company accounting policy election, $0.1 million of penalties and interest related to prior year tax positions was recorded to income tax expense in 2014. In the event interest or penalties are incurred with respect to income tax matters, the Partnership's policy will be to include such items in income tax expense. As of December 31, 2014, tax years 2011 through 2014 remain subject to examination by the Internal Revenue Service and tax years 2010 through 2014 remain subject to examination by various state taxing authorities.

Certain_Provision_of_the_Partn

Certain Provision of the Partnership Agreement	12 Months Ended
	Dec. 31, 2014
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 Appalachian Units.
	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. Through December 2014, the Partnership sold an aggregate of 0.3 million common units under the BMO EDA, generating proceeds of approximately $7.8 million (net of approximately $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes.
	(b) Cash Distributions
	Unless restricted by the terms of the Partnership credit facility and/or the indentures governing the Partnership’s unsecured senior 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.
	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 $20.6 million were earned by our general partner for the year ended December 31, 2014. The Partnership paid annual distributions per common unit of $1.095 for the year ended December 31, 2014.
	The Partnership declared a fourth quarter 2014 distribution on its common units of $0.375 per unit which was paid on February 12, 2015.
	(c) Allocation of Partnership Income
	Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in Note 7(b). The General Partner's share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of 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,
		2014
	Income allocation for incentive distributions	$	20.6

	Unit-based compensation attributable to ENLC’s restricted units	(10.4		)
	General Partner interest in net income	1.1

	General Partner share of net income	$	11.3

Earnings_per_Unit_and_Dilution

Earnings per Unit and Dilution Computations	12 Months Ended
	Dec. 31, 2014
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 share-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. The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions except per unit amounts):


		Year Ended December 31,
		2014*
	Net income attributable to Enlink Midstream, LLC	$	90.5

	Distributed earnings allocated to:
	Common units and Class B Units (1) (2)	$	126.8

	Unvested restricted units (1)	0.8

	Total distributed earnings	$	127.6

	Undistributed loss allocated to:
	Common units and Class B Units (2)	$	(36.9	)
	Unvested restricted units	(0.2		)
	Total undistributed loss	$	(37.1	)
	Net income allocated to:
	Common units and Class B Units (2)	$	89.9

	Unvested restricted units	0.6

	Total net income	$	90.5

	Total basic and diluted net income per unit:
	Basic	$	0.55

	Diluted	$	0.55

	__________________________________________________
	* The 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014.
	(1) The 2014 amount represents distributions of $0.18 per unit paid on May 15, 2014, distributions of $0.22 per unit paid on August 13, 2014, distributions of $0.23 per unit paid on November 14, 2014 and distributions declared of $0.235 per unit payable on February 13, 2014.
	(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 limited partner unit for the year ended December 31, 2014 (in millions):


		Year Ended December 31,
		2014
	Basic and diluted earnings per unit:
	Weighted average limited partner common units outstanding	164

	Diluted weighted average units outstanding:
	Weighted average limited partner basic common units outstanding	164

	Dilutive effect of restricted units issued	0.3

	Total weighted average limited partner diluted common units outstanding	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.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations
	The schedule below summarizes the changes in the Partnership’s asset retirement obligations:


		31-Dec-14		31-Dec-13
		(in millions)
	Beginning asset retirement obligations	$	7.7	$	9.1

	Revisions to existing liabilities	2.2		(1.8		)

	Liabilities acquired	8.7		—

	Accretion	0.5		0.5

	Liabilities settled	—		(0.1		)

	Ending asset retirement obligations	$	19.1	$	7.7


	Asset retirement obligations of $8.2 million as of December 31, 2014 are included in Other Current Liabilities

Investment_in_Unconsolidated_A

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2014
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 benefits and burdens associated with Devon's 38.75% ownership interest in GCF at December 31, 2014 and 2013 and a 30.6% ownership interest in Howard Energy Partners (“HEP”) at December 31, 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
	31-Dec-14
	Distributions	$	11	$	12.7	$	23.7

	Equity in income	$	17.1	$	1.8	$	18.9


	December 31, 2013
	Distributions	$	12	$	—	$	12

	Equity in income	$	14.8	$	—	$	14.8


	December 31, 2012
	Distributions	$	2.3	$	—	$	2.3

	Equity in income	$	2	$	—	$	2

	(1) Includes income and distributions 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):


		31-Dec-14		31-Dec-13
	Gulf Coast Fractionators (1)	$	54.1	$	61.1

	Howard Energy Partners	216.7		—

	Total investments in unconsolidated affiliates	$	270.8	$	61.1


	-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, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Incentive Plans	Employee Incentive Plans
	(a) Long-Term Incentive Plans
	The Partnership and ENLC each have similar unit or unit-based payment plans for employees, which are described below. Unit-based compensation associated with ENLC's 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 and Midstream Holdings. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions):


			Year Ended December 31,
			2014				2013		2012
	Cost of unit-based compensation allocated to Predecessor general and administrative expense (1)		$	2.8			$	12.8	$	12.8

	Cost of unit-based compensation charged to general and administrative expense		16.9				—		—

	Cost of unit-based compensation charged to operating expense		2.7				—		—

	Total amount charged to income		$	22.4			$	12.8	$	12.8

	Interest of non-controlling partners in unit-based compensation		$	8.3			$	—	$	—

	Amount of related income tax expense recognized in income		$	5.3			$	4.8	$	4.8

	(1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity.
	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. On March 7, 2014, the General Partner amended and restated the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “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 awards.
	(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, 2014 is provided below:


	EnLink Midstream Partners, LP Restricted Incentive Units:		Number of				Weighted
			Units				Average
							Grant-Date
							Fair Value
	Non-vested, beginning of period		—				$	—

	Assumed in business combination		371,225				30.51

	Granted		768,989				31.47

	Vested*		(62,428		)		29.4

	Forfeited		(55,595		)		31.35

	Non-vested, end of period		1,022,191				$	31.25

	Aggregate intrinsic value, end of period (in millions)		$	29.7

	_______________________________________________________________________________

	*	Vested units include 24,314 units withheld for payroll taxes paid on behalf of employees.
	Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years. These units are included in the restricted incentive units outstanding and the current unit-based compensation cost calculations as of December 31, 2014. The Partnership issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years.

	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 year ended December 31, 2014 are provided below (in millions):


			Year Ended December 31,
	EnLink Midstream Partners, LP Restricted Incentive Units:		2014
	Aggregate intrinsic value of units vested		$	1.8

	Fair value of units vested		$	1.9

	As of December 31, 2014, there was $20.1 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 1.9 years.
	(c) Unit Options
	During the year ended December 31, 2014, 37,432 unit options of the Partnership were exercised with an intrinsic value of $0.8 million. As of December 31, 2014, all unit options were fully vested and fully expensed.
	(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 awards.
	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, 2014 is provided below:


EnLink Midstream, LLC Restricted Incentive Units:		Number of				Weighted
		Units				Average
						Grant-Date
						Fair Value
Non-vested, beginning of period		—				$	—

Assumed in business combination		435,674				37.6

Granted		678,347				36.71

Vested*		(78,133		)		37.64

Forfeited		(49,416		)		36.75

Non-vested, end of period		986,472				$	37.03

Aggregate intrinsic value, end of period (in millions)		$	35.1

_______________________________________________________________________________
* Vested units include 31,093 shares withheld for payroll taxes paid on behalf of employees.
Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years. These units are included in restricted incentive units outstanding and the current unit-based compensation cost calculations as of December 31, 2014. ENLC issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding.
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, 2014 is provided below (in millions):


		Year Ended December 31,
EnLink Midstream LLC Restricted Incentive Units:		2014
Aggregate intrinsic value of units vested		$	3.1

Fair value of units vested		$	2.9

As of December 31, 2014 there was $20.5 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 1.9 years.
(e) Benefit Plan
The Partnership sponsors a single employer 401(k) plan whereby it matches 100% of up to 6% of an employee’s contribution. Contributions of $5.5 million were made to the plan for the year ended December 31, 2014.

Derivatives

Derivatives	12 Months Ended
Derivatives	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives
	Interest Rate Swaps
	The Partnership entered into interest rate swaps for 9 to 22 days 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):


		December 31,
		2014
	Settlement gains on derivatives	$	3.6
	Settlement gains on derivatives	$	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, NGLs, condensate and crude oil. 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 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, condensate and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude oil, fixed-for-float swaps are used to protect cash flows against price fluctuations: 1) in the NGL component of the Partnership's percentage of liquids contracts, which it receives as a fee for natural gas processing, 2) in the natural gas processing and fractionation components of the Partnership's business and 3) in the storage component of the Partnership's business where it has price risk for product held in inventory or storage.
	The components of gain on derivatives in the consolidated statements of operations relating to commodity swaps are (in millions):


		Year Ended December 31,
		2014*
	Change in fair value of derivatives that are not designated for hedge accounting	$	22.4
		$	22.4
	Settlement losses on derivatives	(0.3		)
	Net gains related to commodity swaps	$	22.1
	Net gains related to commodity swaps	$	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):


		December 31,
		2014
	Fair value of derivative assets — current	$	16.7
	Fair value of derivative assets — current	$	16.7
	Fair value of derivative assets — long term	10
	Fair value of derivative assets — long term	10
	Fair value of derivative liabilities — current	(3.0		)
	Fair value of derivative liabilities — long term	(2.0		)
	Net fair value of derivatives	$	21.7
	Net fair value of derivatives	$	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, 2014. The remaining term of the contracts extend no later than December 2016.


				31-Dec-14
	Commodity	Instruments		Unit	Volume		Fair Value
					(In millions)
	NGL (short contracts)	Swaps		Gallons	(57.0	)	$	26.3
	NGL (short contracts)	Swaps		Gallons	(57.0	)	$	26.3
	NGL (long contracts)	Swaps		Gallons	45.4		(4.5		)
	NGL (long contracts)	Swaps		Gallons	45.4		(4.5		)
	Natural Gas (short contracts)	Swaps		MMBtu	(5.4	)	0.3
	Natural Gas (short contracts)	Swaps		MMBtu	(5.4	)	0.3
	Natural Gas (long contracts)	Swaps		MMBtu	3.1		(0.4		)
	Natural Gas (long contracts)	Swaps		MMBtu	3.1		(0.4		)
	Total fair value of derivatives						$	21.7
	Total fair value of derivatives						$	21.7
	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, 2014 of $26.7 million would be reduced to $21.7 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 loss 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 to			More than		Total
		one year			two years			two years		fair value
	31-Dec-14	$	13.7		$	8		$	—	$	21.7
	31-Dec-14	$	13.7		$	8		$	—	$	21.7

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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 (liabilities) measured at fair value on a recurring basis are summarized below (in millions):


			December 31, 2014
			Level 2
	Commodity Swaps*		$	21.7

	Total		$	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):


			31-Dec-14
			Carrying		Fair
			Value		Value
	Long-term debt		$	2,022.50	$	2,026.10

	Obligations under capital lease		$	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 $237.0 million in outstanding borrowings under its revolving credit facility as of December 31, 2014. 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, 2014, the Partnership had borrowings totaling $399.5 million, $553.2 million, $349.7 million and $298.3 million, net of discount, under the 2019 Notes, 2024 Notes, 2044 Notes and 2045 Notes, with a fixed rate of 2.70%, 4.40%, 5.60% and 5.05% respectively. Additionally, the Partnership had borrowings of $184.4 million, including premium, under the 2022 Notes with a fixed rate of 7.125% as of December 31, 2014. The fair value of all senior unsecured notes as of December 31, 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.

Transcations_with_Related_Part

Transcations with Related Parties	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Transcation with Related Parties	Affiliate Transactions
	The Partnership engages in various transactions with Devon and other affiliated entities. Prior to March 7, 2014, these 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. 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.
	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 economic burdens and benefits of Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination. Assets that were not contributed from the Predecessor are reflected as discontinued operations prior to March 7, 2014 and reflected as a reduction in equity at March 7, 2014. Further, the Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. As a result of the business combination, Midstream Holdings is a legal entity that is treated as a partnership for tax purposes and is not subject to U.S. federal income tax or certain state income taxes in the future. The business combination transactions were treated as a reorganization under common control for tax purposes. Therefore, the elimination of the related deferred tax liability is reflected as an increase in equity.
	Midstream Holdings, in which the Partnership holds a 50% economic interest as of March 7, 2014, conducts business with Devon pursuant to the gathering and processing agreements described below. The legacy Partnership also historically has maintained a relationship with Devon as a customer, as described in more detail below.
	Gathering and Processing Agreements
	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. 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. 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 system 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, 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.
	On August 29, 2014, Gas Services assigned its 10-year gathering and processing agreement 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. Such assignment was effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, Linn Energy is responsible to perform Gas Services' obligations under the agreement, which remains in full force and effect. The assignment of this agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma. Gross operating margin related to our Northridge assets totaled $28.4 million for the year ended December 31, 2014.
	Historical Customer Relationship with Devon
	As noted above, the Partnership maintained a customer relationship with Devon prior to the business combination pursuant to which certain of the Partnership's subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with such Devon subsidiaries. The terms of these agreements vary, but the agreements expire between March 2015 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, one of the Partnership's subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership's subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee. These NGL purchase and sale agreements have month-to-month terms.
	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, including IT, accounting, pipeline integrity, compliance management and procurement services, and the Partnership provides certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. Substantially all services under the transition services agreement were completed during 2014.
	GCF Agreement
	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 Devon agreed, from and after the closing of the business combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% interest in GCF, which owns a fractionation facility in Mont Belvieu, Texas.
	Lone Camp Gas Storage Agreement
	In connection with the closing of the business combination, Midstream Holdings entered into an agreement with Gas Services under which Midstream Holdings provides gas storage services at its Lone Camp storage facility. Under this agreement, Gas Services reimburses Midstream Holdings for the expenses it incurs in providing the storage services. This agreement has minimal to no impact on Midstream Holdings' annual revenue.
	Acacia Transportation Agreement
	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.
	Office Leases
	In connection with the closing of the business combination, the Operating Partnership entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which the Operating Partnership leases office space from Devon at its Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.
	Tax Sharing Agreement
	In connection with the closing of the business combination, the Partnership, ENLC and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due.

	The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which were settled through an adjustment to equity prior to March 7, 2014 (in millions):


			Year Ended December 31,
			2014				2013				2012
	Continuing Operations:
	Operating revenues - affiliates		$	(436.4	)		$	(2,116.5	)		$	(1,753.9	)
	Operating expenses - affiliates		340				1,669.50				1,385.80

	Net affiliate transactions		(96.4		)		(447.0		)		(368.1		)
	Capital expenditures		16.2				244.3				337.2

	Other third-party transactions, net		58.9				51.5				118.7

	Net third-party transactions		75.1				295.8				455.9

	Net cash distributions to Devon - continuing operations		(21.3		)		(151.2		)		87.8

	Non-cash distribution of net assets to Devon		(6.3		)		—				—

	Total net distributions per equity		$	(27.6	)		$	(151.2	)		$	87.8


	Discontinued operations:
	Operating revenues - affiliates		$	(10.4	)		$	(84.6	)		$	(152.0	)
	Operating expenses - affiliates		5				32.7				86.3

	Cash used in financing activities - affiliates		—				(5.6		)		(1.1		)

	Net affiliate transactions		(5.4		)		(57.5		)		(66.8		)
	Capital expenditures		0.6				1.1				26.5

	Other third-party transactions, net		0.4				(72.0		)		(23.6		)

	Net third-party transactions		1				(70.9		)		2.9

	Net distributions to Devon and non-controlling interests - discontinued operations		(4.4		)		(128.4		)		(63.9		)
	Non-cash distribution of net assets to Devon		(39.9		)		—				—

	Total net distributions per equity		$	(44.3	)		$	(128.4	)		$	(63.9	)
Total distributions- continuing and discontinued operations		$	(71.9	)		$	(279.6	)		$	23.9

For the years ended December 31, 2014, 2013, 2012, Devon was a significant customer to the Partnership. Devon accounted for 30.4%, 92.2% and 91.9% of the Partnership's revenues for the year ended December 31, 2014, 2013 and 2012, respectively. The affiliate revenues after March 7, 2014 through December 31, 2014 were $629.2 million. The Partnership had an accounts receivable balance related to transactions with Devon of $120.8 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $3.0 million as of December 31, 2014.
Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the year ended December 31, 2014 and $12.8 million for both 2013 and 2012. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million, $8.7 million and $9.1 million for the year ended December 31, 2014, 2013 and 2012 respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
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):


	2015	$	11.6

	2016	9.2

	2017	6.6

	2018	11.5

	2019	9

	Thereafter	71.2

		$	119.1

	(b) Change of Control and Severance Agreements
	Certain members of management of the Partnership are parties to change of control and/or severance agreements with the General Partner. The change of control and severance agreements provide those managers with severance payments in certain circumstances.
	(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 or results of operations.
	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, 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 or financial condition.
	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. The court’s ruling is subject to appeal. The Partnership intends to vigorously defend the case. 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.
	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 Company, LLC, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the August 2012 sinkhole that formed in the Bayou Corne area of Assumption Parish, Louisiana. The suit is pending in the 23rd 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.
	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 assessing the potential for recovering our losses from responsible parties. The Partnership has sued Texas Brine, LLC, the operator of a failed cavern in the area, and its insurers seeking recovery for this damage. The Partnership also filed a claim with its insurers. The Partnership's insurers denied its claim. The Partnership disputes the denial but have 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 in the amount of $6.1 million. Additional claims related to this matter remain outstanding. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties.
	In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its fractionation plants. 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.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	Segment Information
	Identification of operating segments is based principally upon regions served. The Partnership'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 the Ohio River Valley (“ORV”). The Partnership's sales are derived from external domestic customers.
	The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. 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 and its investments in HEP and GCF. Profit in the corporate segment for the year ended 2014 includes the operating activity for intersegment eliminations and gains on derivative activity. The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits.
	Summarized financial information concerning the Partnership's reportable segments is shown in the following table:


			Texas				Louisiana				Oklahoma			Ohio River Valley			Corporate			Totals
			(In millions)
	Year Ended December 31, 2014:
	Sales to external customers		$	284.3			$	1,852.30			$	14.8		$	261.3		$	—		$	2,412.70

	Sales to affiliates		782.9				73.2				304			—			(94.5		)	1,065.60

	Purchased gas, NGLs, condensate and crude oil		(490.9		)		(1,754.2		)		(142.5		)	(201.4		)	94.5			(2,494.5		)

	Operating expenses		(145.4		)		(68.2		)		(28.6		)	(36.0		)	—			(278.2		)

	Gain on litigation settlement		—				6.1				—			—			—			6.1

	Gain on derivative activity		—				—				—			—			22.1			22.1

	Segment profit		$	430.9			$	109.2			$	147.7		$	23.9		$	22.1		$	733.8

	Depreciation, amortization and impairments		$	(125.9	)		$	(69.3	)		$	(49.4	)	$	(33.0	)	$	(2.7	)	$	(280.3	)
	Goodwill		$	1,168.20			$	786.8			$	190.3		$	112.5		$	1,426.90		$	3,684.70

	Capital expenditures		$	271			$	273.1			$	17.1		$	153		$	13.9		$	728.1

	Year Ended December 31, 2013:
	Sales to external customers		$	129.3			$	—			$	50.1		$	—		$	—		$	179.4

	Sales to affiliates		1,419.80				—				696.7			—			—			2,116.50

	Purchased gas, NGLs, condensate and crude oil		(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, amortization and impairments		$	(110.6	)		$	—			$	(76.4	)	$	—		$	—		$	(187.0	)

	Goodwill		$	325.4			$	—			$	76.3		$	—		$	—		$	401.7

	Capital expenditures		$	147			$	—			$	66.1		$	—		$	—		$	213.1

	Year Ended December 31, 2012:
	Sales to external customers		$	124.4			$	—			$	29.5		$	—		$	—		$	153.9

	Sales to affiliates		1,232.80				—				521.1			—			—			1,753.90

	Purchased gas, NGLs, condensate and crude oil		(983.3		)		—				(444.8		)	—			—			(1,428.1		)

	Operating expenses		(119.8		)		—				(30.1		)	—			—			(149.9		)

	Segment profit		$	254.1			$	—			$	75.7		$	—		$	—		$	329.8

	Depreciation, amortization and impairments		$	(98.3	)		$	—			$	(63.5	)	$	—		$	—		$	(161.8	)

	Goodwill		$	325.4			$	—			$	76.3		$	—		$	—		$	401.7

	Capital expenditures		$	142.4			$	—			$	209.3		$	—		$	—		$	351.7







The table below represents information about segment assets as of December 31, 2014, 2013 and 2012:


		Years Ended December 31,
Segment Identifiable Assets:		2014				2013
Texas		$	3,303.00			$	1,460.00

Louisiana		3,316.50				—

Oklahoma		892.8				777.1

Ohio River Valley		762.5				—

Corporate		1,822.50				72.7

Total identifiable assets		$	10,097.30			$	2,309.80

The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in millions):


		Years Ended December 31,
		2014				2013				2012
Segment profits		$	733.8			$	403.4			$	329.8

General and administrative expenses		(97.3		)		(45.1		)		(41.7		)
Depreciation, amortization and impairments		(280.3		)		(187.0		)		(161.8		)
Gain on sale of property		0.1				—				—

Operating income		$	356.3			$	171.3			$	126.3

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
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. Therefore, the Predecessor's non-contributed historical assets and liabilities are presented as held for sale as of December 31, 2013. 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):


		Years Ended December 31,
		2014		2013			2012
	Operating revenues:
	Operating revenues	$	6.8	$	42.1		$	53.1

	Operating revenues - affiliates	10.5		84.6			152

	Total operating revenues	17.3		126.7			205.1


	Operating expenses:
	Operating expenses:	15.7		130.3			213.2

	Total operating expenses	15.7		130.3			213.2


	Income (loss) before income taxes	1.6		(3.6		)	(8.1		)

	Income tax provision (benefit)	0.6		(1.3		)	(2.9		)

	Net income (loss)	1		(2.3		)	(5.2		)

	Net income attributable to non-controlling interest	—		(1.3		)	(1.1		)

	Net income (loss) including non-controlling interest	$	1	$	(3.6	)	$	(6.3	)

	The following table presents the main classes of assets and liabilities associated with the Partnership's discontinued operations at December 31, 2013. There were no assets and liabilities associated with discontinued operations at December 31, 2014:


		31-Dec-13
		(in millions)
	Inventories	$	0.2

	Other current assets	0.2

	Total current assets	0.4

	Property, plant & equipment	72.3

	Total assets	$	72.7


	Accounts payable	$	3.2

	Other current liabilities	1.1

	Total current liabilities	4.3

	Asset retirement obligations	7.1

	Deferred income taxes	25.3

	Other long-term liabilities	0.3

	Total liabilities	$	37

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
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)
	2014:00:00
	Revenues	$	723	$	927.2	$	855	$	995.2	$	3,500.40

	Operating income	$	74	$	91.9	$	89.3	$	101.1	$	356.3

	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	$	42.3	$	28.8	$	28.8	$	26.1	$	126

	Income per common unit-basic	$	0.04	$	0.18	$	0.18	$	0.16	$	0.55

	Income per common unit-diluted	$	0.04	$	0.18	$	0.17	$	0.16	$	0.55

	2013:00:00
	Revenues	$	526.9	$	588	$	578.2	$	602.8	$	2,295.90

	Operating income	$	35.9	$	42.6	$	48.1	$	44.7	171.3

	Net income attributable to EnLink Midstream, LLC	$	29.4	$	32.8	$	30.3	$	23	$	115.5

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	Midstream Holdings Drop Down. On February 17, 2015, Acacia, a wholly-owned subsidiary of ENLC, sold a 25% limited partner interest in Midstream Holdings (the “Transferred Interest”) to the Partnership in a drop-down transaction (the “EMH Drop Down”). As consideration for the Transferred Interest, the Acacia received 31.6 million Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units are substantially similar in all respects to the Partnership’s common units, except that they will only be entitled to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units will automatically convert into common units on a one-for-one basis on the first business day following the record date for distribution payments with respect to the distribution for the quarter ended March 31, 2015.After giving effect to the EMH Drop Down, the Partnership indirectly owns a 75% limited partner interest in Midstream Holdings, with Acacia owning the remaining 25% limited partner interest in Midstream Holdings.
	The Partnership's Credit Facility Amendment. On February 5, 2015, the commitments under the Partnership credit facility were increased to $1.5 billion and the maturity date was extended by a year to March 6, 2020.
	LPC Acquisition. On January 31, 2015, the Partnership, through one of its wholly owned subsidiaries, acquired LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million, subject to certain adjustments.

Condensed_Financial_Informatio

Condensed Financial Information of Parent Company Only (Notes)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent Company Only	CONDENSED BALANCE SHEET


			December 31,
			2014
			(In millions)
	ASSETS
	Current assets:
	Cash and cash equivalents		$	58.8

	Accounts receivable		—

	Related party receivable		2.4

	Prepaid expenses and other		1.1

	Total current assets		62.3

	Goodwill		1,426.90

	Investment in equity investments		1,723.00

	Other assets, net		0.9

	Total assets		$	3,213.10

	LIABILITIES AND MEMBERS' EQUITY
	Current liabilities:
	Other current liabilities		$	2.2

	Total current liabilities		2.2

	Deferred tax liability		436.6

	Members' equity:
	Members' equity		2,774.30

	Total members' equity		2,774.30

	Total liabilities and members' equity		$	3,213.10

	CONDENSED STATEMENTS OF OPERATIONS


			Years ended December 31,
			2014
			(In millions, except per share data)
	Revenues:
	Income from equity investments		$	185.7

	Total revenues		185.7

	Operating costs and expenses:
	General and administrative expenses		3

	Total operating costs and expenses		3

	Operating income		182.7

	Other income (expense):
	Interest and other income		(2.4		)
	Income before income taxes		180.3

	Income tax provision		(54.3		)
Net income		$	126

Net income attributable to EnLink Midstream, LLC per unit:
Basic		$	0.55

Diluted		$	0.55

Weighted average common units outstanding:
Basic		$	164

Diluted		$	164.3

CONDENSED STATEMENT OF CASH FLOWS


		Years Ended December 31,
		2014
		(In millions)
Cash flows from operating activities:
Net income		$	126

Adjustments to reconcile net income to net cash used in operating activities:
Income from equity investments		(185.7		)
Deferred tax benefit		52

Stock-based compensation		0.2

Amortization of debt issue cost		0.2

Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other		(1.5		)
Accounts payable, and other accrued liabilities		(13.5		)
Net cash used in operating activities		(22.3		)
Cash flows from investing activities:
Proceeds from sale of investment		163

Acquisition of business		(16.7		)
Distributions from the affiliates		194.9

Acquisition of non-controlling interest		(93.5		)
Net cash provided by investing activities		247.7

Cash flows from financing activities:
Proceeds from borrowings		216.3

Payments on borrowings		(291.5		)
Debt refinancing cost		(1.1		)
Conversion of restricted units, net of units withheld for taxes		(1.3		)
Distribution to members		(89.0		)
Net cash used in financing activities		(166.6		)
Net increase in cash and cash equivalents		58.8

Cash, beginning of period		—

Cash, end of period		$	58.8

Non-cash transactions:
Loss from issuance of Partnership units		$	1.8

Significant_Accounting_Policy_

Significant Accounting Policy (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Accounting

Basis of Presentation

Management's Use of Estimates

Revenue Recognition

The Company 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

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

Property, Plant, and Equipment

The components of property, plant and equipment are as follows (in millions):

December 31,

2014

2013

Transmission assets

1,270.30

95.9

Gathering systems

2,391.90

1,617.80

Gas processing plants

2,356.10

1,223.70

Other property and equipment

104

0.5

Construction in process

234.3

—

Property, plant and equipment

6,356.60

2,937.90

Accumulated depreciation and amortization

(1,422.3

)

(1,169.8

)

Property, plant and equipment, net

4,934.30

1,768.10

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 $243.8 million, $187.0 million and $145.4 million was recorded for the years ended December 31, 2014, 2013 and 2012, respectively.

Equity Method of Accounting

The Company evaluates its equity investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable.

Goodwill and Intangible Assets, Goodwill

Goodwill

Intangible Assets

The following table represents the Partnership's total purchased intangible assets at years ended December 31, 2014 (in millions):

Gross

Accumulated

Net

Carrying

Amortization

Carrying

Amount

Customer relationships

569.5

(36.5

)

533

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $36.5 million for the year ended December 31, 2014.

The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions):

2015

44.5

2016

44.5

2017

44.5

2018

44.5

2019

43.6

Thereafter

311.4

Total

533

Asset Retirement Obligations

Other Long-Term Liabilities

Derivatives

Concentrations of Credit Risk

Environmental Costs

Unit-Based Awards

Commitments and Contingencies

Discontinued Operations

Recent Accounting Pronouncements

Other Assets

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.

Significant_Accounting_Policy_1

Significant Accounting Policy (Tables)	12 Months Ended
Significant Accounting Policy (Tables)	Dec. 31, 2014
Accounting Policies [Abstract]
Property, Plant and Equipment	The components of property, plant and equipment are as follows (in millions):


			December 31,
			2014			2013
	Transmission assets		$	1,270.30		$	95.9
	Transmission assets		$	1,270.30		$	95.9
	Gathering systems		2,391.90			1,617.80
	Gathering systems		2,391.90			1,617.80
	Gas processing plants		2,356.10			1,223.70
	Gas processing plants		2,356.10			1,223.70
	Other property and equipment		104			0.5
	Other property and equipment		104			0.5
	Construction in process		234.3			—
	Construction in process		234.3			—
	Property, plant and equipment		6,356.60			2,937.90
	Property, plant and equipment		6,356.60			2,937.90
	Accumulated depreciation and amortization		(1,422.3		)	(1,169.8		)
	Property, plant and equipment, net		$	4,934.30		$	1,768.10
	Property, plant and equipment, net		$	4,934.30		$	1,768.10
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
Schedule of Goodwill	The table below provides a summary of the Company’s goodwill, by assigned reporting unit.


			December 31,			December 31,
			2014			2013
			(in millions)
	Texas		$	1,168.20		$	325.4
	Texas		$	1,168.20		$	325.4
	Louisiana		786.8			—
	Louisiana		786.8			—
	Oklahoma		190.3			76.3
	Oklahoma		190.3			76.3
	Ohio River Valley		112.5			—
	Ohio River Valley		112.5			—
	Corporate		1,426.90			—
	Corporate		1,426.90			—
	Total		$	3,684.70		$	401.7
	Total		$	3,684.70		$	401.7
Schedule of Finite-Lived Intangible Assets	The following table represents the Partnership's total purchased intangible assets at years ended December 31, 2014 (in millions):


			Gross			Accumulated			Net
			Carrying			Amortization			Carrying
			Amount						Amount
	Customer relationships		$	569.5		$	(36.5	)	$	533
	Customer relationships		$	569.5		$	(36.5	)	$	533
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):


	2015	$	44.5
	2015	$	44.5
	2016	44.5
	2016	44.5
	2017	44.5
	2017	44.5
	2018	44.5
	2018	44.5
	2019	43.6
	2019	43.6
	Thereafter	311.4
	Thereafter	311.4
	Total	$	533
	Total	$	533

Acquisition_Table

Acquisition (Table)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following unaudited pro forma condensed financial data for the year ended December 31, 2014 and 2013 gives effect to the business combination, Chevron acquisition and E2 drop down as if they had occurred on January 1, 2013. The 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. As of March 7, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 4. Pro forma financial information associated with the business combination and with these agreements with Devon is reflected below.


			Year Ended December 31,
			2014			2013
			(in millions except for per unit data)
	Pro forma total revenues		$	3,698.20		$	2,597.90

	Pro forma net income		$	240.1		$	102.4

	Pro forma net income attributable to Enlink Midstream, LLC		$	67.5		$	70.4

	Pro forma net income per common unit:
	Basic		$	0.41		$	0.43

	Diluted		$	0.41		$	0.43

Chevron Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table is a preliminary summary of the fair value of the assets acquired and liabilities assumed:


	Purchase Price Allocation (in millions):
	Assets acquired:
	Property, plant and equipment		$	242.2

	Liabilities assumed:
	Current liabilities		(10.7		)
	Total purchase price		$	231.5

Devon Merger
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table is a summary of the fair value of the assets acquired and liabilities assumed from EMI in the business combination as of March 7, 2014:


	Purchase Price Allocation (in millions):
	Assets acquired:
	Current assets	$	437.4

	Property, plant and equipment	2,437.90

	Intangibles assets	569.4

	Equity investment	221.5

	Goodwill	3,283.10

	Other long term assets	1.3

	Liabilities assumed:
	Current liabilities	(515.0		)
	Long-term debt	(1,453.7		)
	Deferred taxes	(210.4		)
	Other long term liabilities	(101.2		)
	Total purchase price	$	4,670.30

Schedule of Business Acquisitions, by Acquisition	The following table summarizes the purchase price (in millions, except per unit price):


	EMI outstanding common shares:
	Held by public shareholders	48

	Restricted shares	0.4

	Total subject to exchange	48.4

	Exchange ratio	1			x

	Exchanged shares	48.4

	EMI common share price(1)	$	37.6

	EMI consideration	$	1,822.60

	Fair value of non-controlling interests in E2	18.9

	Total consideration and fair value of non-controlling interests	$	1,841.50

	Partnership outstanding units:
	Common units held by public unitholders	75.1

	Preferred units held by third party (2)	17.1

	Restricted units	0.4

	Total	92.6

	Partnership common unit price(3)	$	30.51

	Partnership common units value	$	2,825.20

	Partnership outstanding unit options value	$	3.9

	Total fair value of non-controlling interests in the Partnership(3)	$	2,828.80

	Total consideration and fair value of non-controlling interests	$	4,670.30

	(1) The final purchase price is based on the fair value of the Company's common shares as of the closing date, March 7, 2014.
	(2) The Partnership converted the preferred units to common units in February 2014.
	(3) The final purchase price is based on the fair value of the Partnership's common units as of the closing date, March 7, 2014.

Affiliate_Transactions_Tables

Affiliate Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which were settled through an adjustment to equity prior to March 7, 2014 (in millions):


		Year Ended December 31,
		2014			2013			2012
	Continuing Operations:
	Operating revenues - affiliates	$	(436.4	)	$	(2,116.5	)	$	(1,753.9	)
	Operating expenses - affiliates	340			1,669.50			1,385.80

	Net affiliate transactions	(96.4		)	(447.0		)	(368.1		)
	Capital expenditures	16.2			244.3			337.2

	Other third-party transactions, net	58.9			51.5			118.7

	Net third-party transactions	75.1			295.8			455.9

	Net cash distributions to Devon - continuing operations	(21.3		)	(151.2		)	87.8

	Non-cash distribution of net assets to Devon	(6.3		)	—			—

	Total net distributions per equity	$	(27.6	)	$	(151.2	)	$	87.8


	Discontinued operations:
	Operating revenues - affiliates	$	(10.4	)	$	(84.6	)	$	(152.0	)
	Operating expenses - affiliates	5			32.7			86.3

	Cash used in financing activities - affiliates	—			(5.6		)	(1.1		)

	Net affiliate transactions	(5.4		)	(57.5		)	(66.8		)
	Capital expenditures	0.6			1.1			26.5

	Other third-party transactions, net	0.4			(72.0		)	(23.6		)

	Net third-party transactions	1			(70.9		)	2.9

	Net distributions to Devon and non-controlling interests - discontinued operations	(4.4		)	(128.4		)	(63.9		)
	Non-cash distribution of net assets to Devon	(39.9		)	—			—

	Total net distributions per equity	$	(44.3	)	$	(128.4	)	$	(63.9	)
	Total distributions- continuing and discontinued operations	$	(71.9	)	$	(279.6	)	$	23.9

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
Long-Term Debt (Tables)	Dec. 31, 2014
Debt Disclosure [Abstract]
Indebtedness Table	As of December 31, 2014, long-term debt consisted of the following (in millions):


			2014
	Partnership credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at December 31, 2014 was 1.9%		$	237
			$	237
	Company bank credit facility (due 2019)		—
	Company bank credit facility (due 2019)		—
	The Partnership's senior unsecured notes (due 2019), net of discount of $0.5 million, which bear interest at the rate of 2.70%		399.5
			399.5
	The Partnership's senior unsecured notes (due 2022), including a premium of $21.9 million, which bear interest at the rate of 7.125%		184.4
			184.4
	The Partnership's senior unsecured notes (due 2024), including a premium of $3.2 million, which bear interest at the rate of 4.40%		553.2
			553.2
	The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million, which bear interest at the rate of 5.60%		349.7
			349.7
	The Partnership's senior unsecured notes (due 2045), net of discount of $1.7 million, which bear interest at the rate of 5.05%		298.3
			298.3
	Other debt		0.4
	Other debt		0.4
	Debt classified as long-term		$	2,022.50
	Debt classified as long-term		$	2,022.50
Schedule of Maturities of Long-term Debt	Maturities. Maturities for the long-term debt as of December 31, 2014 are as follows (in millions):


	2015	$	0.2
	2015	$	0.2
	2016	0.1
	2016	0.1
	2017	0.1
	2017	0.1
	2018	—
	2018	—
	2019	637
	2019	637
	Thereafter	1,362.40
	Thereafter	1,362.40
	Subtotal	1,999.80
	Subtotal	1,999.80
	Less: premium (discount)	22.7
	Less: premium (discount)	22.7
	Total outstanding debt	$	2,022.50
	Total outstanding debt	$	2,022.50
Schedule of Debt Leverage

	Pricing Level		Debt Ratings		Applicable Rate Commitment Fee	EuroDollar Rate/Letter of Credit	Base Rate +
	1		A-/A3 or better		0.10%	1.00%	—%
	2		BBB+/Baa1		0.13%	1.13%	0.13%
	3		BBB/Baa2		0.18%	1.25%	0.25%
	4		BBB-/Baa3		0.22%	1.50%	0.50%
	5		BB+/Ba1		0.27%	1.63%	0.63%
	6		BB/Ba2 or worse		0.35%	1.75%	0.75%

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Components of income tax from continuing operations are as follows (in millions):


		Years Ended December 31,
		2014			2013			2012
	Current income tax expense
	Current tax expense	$	9		$	31.5		$	59.1

	Deferred tax expense	67.4			35.5			(12.9		)

	Total income tax expense	$	76.4		$	67		$	46.2

	The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income from continuing operations before income taxes (in millions):


		Years Ended December 31,
		2014			2013			2012
	Expected income tax expense based on federal statutory rate of 35%	$	70.7		$	65.1		$	44.6

	State income taxes, net of federal benefit and other	5.7			1.9			1.6

	Total income tax expense	$	76.4		$	67		$	46.2

Schedule of Deferred Tax Assets and Liabilities	The tax effects of temporary differences that gave rise to significant portions of the Predecessor’s deferred tax assets and liabilities are presented below (in millions):


		Years Ended December 31,
		2014			2013
	Deferred income tax assets:
	Asset retirement obligations	$	2		$	2.8

	State net operating loss carryforward, non current	4.2			—

	Federal net operating loss carryforward, current	16.9			0.4

	Total deferred tax assets	23.1			3.2

	Deferred tax liabilities:
	Property, plant, equipment, and intangible assets, non current	(523.5		)	(444.1		)
	Other	(9.3		)	—

	Total deferred tax liabilities	(532.8		)	(444.1		)
	Deferred tax liability, net	$	(509.7	)	$	(440.9	)
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):


	Balance as of December 31, 2013	$	—

	Unrecognized tax positions assumed in merger	3.8

	Decrease due to prior year tax positions	(2.0		)
	Increases due to current year tax positions	0.2

	Balance as of December 31, 2014	$	2

Certain_Provision_of_the_Partn1

Certain Provision of the Partnership Agreement (Tables)	12 Months Ended
	Dec. 31, 2014
Partners' Capital [Abstract]
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,
		2014
	Income allocation for incentive distributions	$	20.6

	Unit-based compensation attributable to ENLC’s restricted units	(10.4		)
	General Partner interest in net income	1.1

	General Partner share of net income	$	11.3

Earnings_per_Unit_and_Dilution1

Earnings per Unit and Dilution Computations (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions except per unit amounts):


		Year Ended December 31,
		2014*
	Net income attributable to Enlink Midstream, LLC	$	90.5

	Distributed earnings allocated to:
	Common units and Class B Units (1) (2)	$	126.8

	Unvested restricted units (1)	0.8

	Total distributed earnings	$	127.6

	Undistributed loss allocated to:
	Common units and Class B Units (2)	$	(36.9	)
	Unvested restricted units	(0.2		)
	Total undistributed loss	$	(37.1	)
	Net income allocated to:
	Common units and Class B Units (2)	$	89.9

	Unvested restricted units	0.6

	Total net income	$	90.5

	Total basic and diluted net income per unit:
	Basic	$	0.55

	Diluted	$	0.55

	__________________________________________________
	* The 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014.
	(1) The 2014 amount represents distributions of $0.18 per unit paid on May 15, 2014, distributions of $0.22 per unit paid on August 13, 2014, distributions of $0.23 per unit paid on November 14, 2014 and distributions declared of $0.235 per unit payable on February 13, 2014.
	(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 limited partner unit for the year ended December 31, 2014 (in millions):


		Year Ended December 31,
		2014
	Basic and diluted earnings per unit:
	Weighted average limited partner common units outstanding	164

	Diluted weighted average units outstanding:
	Weighted average limited partner basic common units outstanding	164

	Dilutive effect of restricted units issued	0.3

	Total weighted average limited partner diluted common units outstanding	164.3

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Table)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The schedule below summarizes the changes in the Partnership’s asset retirement obligations:


		31-Dec-14		31-Dec-13
		(in millions)
	Beginning asset retirement obligations	$	7.7	$	9.1

	Revisions to existing liabilities	2.2		(1.8		)

	Liabilities acquired	8.7		—

	Accretion	0.5		0.5

	Liabilities settled	—		(0.1		)

	Ending asset retirement obligations	$	19.1	$	7.7

Investment_in_Unconsolidated_A1

Investment in Unconsolidated Affiliate (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):


		31-Dec-14		31-Dec-13
	Gulf Coast Fractionators (1)	$	54.1	$	61.1

	Howard Energy Partners	216.7		—

	Total investments in unconsolidated affiliates	$	270.8	$	61.1


	-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.
	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
	31-Dec-14
	Distributions	$	11	$	12.7	$	23.7

	Equity in income	$	17.1	$	1.8	$	18.9


	December 31, 2013
	Distributions	$	12	$	—	$	12

	Equity in income	$	14.8	$	—	$	14.8


	December 31, 2012
	Distributions	$	2.3	$	—	$	2.3

	Equity in income	$	2	$	—	$	2

	(1) Includes income and distributions for the period from March 7, 2014 through December 31, 2014.

Employee_Incentive_Plans_Table

Employee Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
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,
			2014			2013		2012
	Cost of unit-based compensation allocated to Predecessor general and administrative expense (1)		$	2.8		$	12.8	$	12.8

	Cost of unit-based compensation charged to general and administrative expense		16.9			—		—

	Cost of unit-based compensation charged to operating expense		2.7			—		—

	Total amount charged to income		$	22.4		$	12.8	$	12.8

	Interest of non-controlling partners in unit-based compensation		$	8.3		$	—	$	—

	Amount of related income tax expense recognized in income		$	5.3		$	4.8	$	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 activity for the year ended December 31, 2014 is provided below:


	EnLink Midstream Partners, LP Restricted Incentive Units:		Number of			Weighted
			Units			Average
						Grant-Date
						Fair Value
	Non-vested, beginning of period		—			$	—

	Assumed in business combination		371,225			30.51

	Granted		768,989			31.47

	Vested*		(62,428		)	29.4

	Forfeited		(55,595		)	31.35

	Non-vested, end of period		1,022,191			$	31.25

	Aggregate intrinsic value, end of period (in millions)		$	29.7

	_______________________________________________________________________________

	*	Vested units include 24,314 units withheld for payroll taxes paid on behalf of employees.
	A summary of the restricted incentive unit activities for the year ended December 31, 2014 is provided below:


	EnLink Midstream, LLC Restricted Incentive Units:		Number of			Weighted
			Units			Average
						Grant-Date
						Fair Value
	Non-vested, beginning of period		—			$	—

	Assumed in business combination		435,674			37.6

	Granted		678,347			36.71

	Vested*		(78,133		)	37.64

	Forfeited		(49,416		)	36.75

	Non-vested, end of period		986,472			$	37.03

	Aggregate intrinsic value, end of period (in millions)		$	35.1

	_______________________________________________________________________________
	* Vested units include 31,093 shares 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 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, 2014 is provided below (in millions):


			Year Ended December 31,
	EnLink Midstream LLC Restricted Incentive Units:		2014
	Aggregate intrinsic value of units vested		$	3.1

	Fair value of units vested		$	2.9

	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 year ended December 31, 2014 are provided below (in millions):


			Year Ended December 31,
	EnLink Midstream Partners, LP Restricted Incentive Units:		2014
	Aggregate intrinsic value of units vested		$	1.8

	Fair value of units vested		$	1.9

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
Derivatives (Tables)	Dec. 31, 2014
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):


		December 31,
		2014
	Settlement gains on derivatives	$	3.6
	Settlement gains on derivatives	$	3.6
Commodity Swap	The components of gain on derivatives in the consolidated statements of operations relating to commodity swaps are (in millions):


		Year Ended December 31,
		2014*
	Change in fair value of derivatives that are not designated for hedge accounting	$	22.4
		$	22.4
	Settlement losses on derivatives	(0.3		)
	Net gains related to commodity swaps	$	22.1
	Net gains related to commodity swaps	$	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):


		December 31,
		2014
	Fair value of derivative assets — current	$	16.7
	Fair value of derivative assets — current	$	16.7
	Fair value of derivative assets — long term	10
	Fair value of derivative assets — long term	10
	Fair value of derivative liabilities — current	(3.0		)
	Fair value of derivative liabilities — long term	(2.0		)
	Net fair value of derivatives	$	21.7
	Net fair value of derivatives	$	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, 2014. The remaining term of the contracts extend no later than December 2016.


				31-Dec-14
	Commodity	Instruments		Unit	Volume		Fair Value
					(In millions)
	NGL (short contracts)	Swaps		Gallons	(57.0	)	$	26.3
	NGL (short contracts)	Swaps		Gallons	(57.0	)	$	26.3
	NGL (long contracts)	Swaps		Gallons	45.4		(4.5		)
	NGL (long contracts)	Swaps		Gallons	45.4		(4.5		)
	Natural Gas (short contracts)	Swaps		MMBtu	(5.4	)	0.3
	Natural Gas (short contracts)	Swaps		MMBtu	(5.4	)	0.3
	Natural Gas (long contracts)	Swaps		MMBtu	3.1		(0.4		)
	Natural Gas (long contracts)	Swaps		MMBtu	3.1		(0.4		)
	Total fair value of derivatives						$	21.7
	Total fair value of derivatives						$	21.7
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 to			More than		Total
		one year			two years			two years		fair value
	31-Dec-14	$	13.7		$	8		$	—	$	21.7
	31-Dec-14	$	13.7		$	8		$	—	$	21.7

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Derivative Instrument	Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions):


			December 31, 2014
			Level 2
	Commodity Swaps*		$	21.7

	Total		$	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	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):


			31-Dec-14
			Carrying		Fair
			Value		Value
	Long-term debt		$	2,022.50	$	2,026.10

	Obligations under capital lease		$	20.3	$	19.8

Commitments_and_Contingencies_

Commitments and Contingencies Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
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):


	2015	$	11.6

	2016	9.2

	2017	6.6

	2018	11.5

	2019	9

	Thereafter	71.2

		$	119.1

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Partnership Reportable Segement	Summarized financial information concerning the Partnership's reportable segments is shown in the following table:


			Texas				Louisiana			Oklahoma			Ohio River Valley			Corporate			Totals
			(In millions)
	Year Ended December 31, 2014:
	Sales to external customers		$	284.3			$	1,852.30		$	14.8		$	261.3		$	—		$	2,412.70

	Sales to affiliates		782.9				73.2			304			—			(94.5		)	1,065.60

	Purchased gas, NGLs, condensate and crude oil		(490.9		)		(1,754.2		)	(142.5		)	(201.4		)	94.5			(2,494.5		)

	Operating expenses		(145.4		)		(68.2		)	(28.6		)	(36.0		)	—			(278.2		)

	Gain on litigation settlement		—				6.1			—			—			—			6.1

	Gain on derivative activity		—				—			—			—			22.1			22.1

	Segment profit		$	430.9			$	109.2		$	147.7		$	23.9		$	22.1		$	733.8

	Depreciation, amortization and impairments		$	(125.9	)		$	(69.3	)	$	(49.4	)	$	(33.0	)	$	(2.7	)	$	(280.3	)
	Goodwill		$	1,168.20			$	786.8		$	190.3		$	112.5		$	1,426.90		$	3,684.70

	Capital expenditures		$	271			$	273.1		$	17.1		$	153		$	13.9		$	728.1

	Year Ended December 31, 2013:
	Sales to external customers		$	129.3			$	—		$	50.1		$	—		$	—		$	179.4

	Sales to affiliates		1,419.80				—			696.7			—			—			2,116.50

	Purchased gas, NGLs, condensate and crude oil		(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, amortization and impairments		$	(110.6	)		$	—		$	(76.4	)	$	—		$	—		$	(187.0	)

	Goodwill		$	325.4			$	—		$	76.3		$	—		$	—		$	401.7

	Capital expenditures		$	147			$	—		$	66.1		$	—		$	—		$	213.1

	Year Ended December 31, 2012:
	Sales to external customers		$	124.4			$	—		$	29.5		$	—		$	—		$	153.9

	Sales to affiliates		1,232.80				—			521.1			—			—			1,753.90

	Purchased gas, NGLs, condensate and crude oil		(983.3		)		—			(444.8		)	—			—			(1,428.1		)

	Operating expenses		(119.8		)		—			(30.1		)	—			—			(149.9		)

	Segment profit		$	254.1			$	—		$	75.7		$	—		$	—		$	329.8

	Depreciation, amortization and impairments		$	(98.3	)		$	—		$	(63.5	)	$	—		$	—		$	(161.8	)

	Goodwill		$	325.4			$	—		$	76.3		$	—		$	—		$	401.7

	Capital expenditures		$	142.4			$	—		$	209.3		$	—		$	—		$	351.7







The table below represents information about segment assets as of December 31, 2014, 2013 and 2012:


		Years Ended December 31,
Segment Identifiable Assets:		2014				2013
Texas		$	3,303.00			$	1,460.00

Louisiana		3,316.50				—

Oklahoma		892.8				777.1

Ohio River Valley		762.5				—

Corporate		1,822.50				72.7

Total identifiable assets		$	10,097.30			$	2,309.80

Segment Table reconciliation to Condensed Consolidated Financial Statement	The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in millions):


			Years Ended December 31,
			2014				2013			2012
	Segment profits		$	733.8			$	403.4		$	329.8

	General and administrative expenses		(97.3		)		(45.1		)	(41.7		)
	Depreciation, amortization and impairments		(280.3		)		(187.0		)	(161.8		)
	Gain on sale of property		0.1				—			—

	Operating income		$	356.3			$	171.3		$	126.3

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2014
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)
	2014:00:00
	Revenues	$	723	$	927.2	$	855	$	995.2	$	3,500.40

	Operating income	$	74	$	91.9	$	89.3	$	101.1	$	356.3

	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	$	42.3	$	28.8	$	28.8	$	26.1	$	126

	Income per common unit-basic	$	0.04	$	0.18	$	0.18	$	0.16	$	0.55

	Income per common unit-diluted	$	0.04	$	0.18	$	0.17	$	0.16	$	0.55

	2013:00:00
	Revenues	$	526.9	$	588	$	578.2	$	602.8	$	2,295.90

	Operating income	$	35.9	$	42.6	$	48.1	$	44.7	171.3

	Net income attributable to EnLink Midstream, LLC	$	29.4	$	32.8	$	30.3	$	23	$	115.5

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
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):


		Years Ended December 31,
		2014		2013			2012
	Operating revenues:
	Operating revenues	$	6.8	$	42.1		$	53.1

	Operating revenues - affiliates	10.5		84.6			152

	Total operating revenues	17.3		126.7			205.1


	Operating expenses:
	Operating expenses:	15.7		130.3			213.2

	Total operating expenses	15.7		130.3			213.2


	Income (loss) before income taxes	1.6		(3.6		)	(8.1		)

	Income tax provision (benefit)	0.6		(1.3		)	(2.9		)

	Net income (loss)	1		(2.3		)	(5.2		)

	Net income attributable to non-controlling interest	—		(1.3		)	(1.1		)

	Net income (loss) including non-controlling interest	$	1	$	(3.6	)	$	(6.3	)

	The following table presents the main classes of assets and liabilities associated with the Partnership's discontinued operations at December 31, 2013. There were no assets and liabilities associated with discontinued operations at December 31, 2014:


		31-Dec-13
		(in millions)
	Inventories	$	0.2

	Other current assets	0.2

	Total current assets	0.4

	Property, plant & equipment	72.3

	Total assets	$	72.7


	Accounts payable	$	3.2

	Other current liabilities	1.1

	Total current liabilities	4.3

	Asset retirement obligations	7.1

	Deferred income taxes	25.3

	Other long-term liabilities	0.3

	Total liabilities	$	37

Organization_and_Summary_of_Si1

Organization and Summary of Significant Agreements (Details Textuals)	0 Months Ended	12 Months Ended	0 Months Ended
	Oct. 22, 2014	Dec. 31, 2014	Feb. 16, 2015
Business Acquisition [Line Items]
Partnership name		EnLink Midstream Partners GP, LLC
Total units exchanged	1,000,000	115,495,669
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited partner interest		7.10%
Common units		17,431,152
Ownership interest		0.70%
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%
Subsequent Event \| Enlink midstream, LLC
Business Acquisition [Line Items]
Limited partner interest			25.00%

Significant_Accounting_Policie1

Significant Accounting Policies (Gas Imbalances and Other Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Gas Imbalance Asset Liability [Abstract]
Gas Balancing Payable	$1,500,000
Gas Balancing Receivable	1,200,000	0
Other Assets [Abstract]
Unamortized debt issuance costs	$17,500,000

Significant_Accounting_Policie2

Significant Accounting Policies (Property Plant and Equipment) (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$6,356,600,000	$2,937,900,000
Accumulated depreciation and amortization	-1,422,300,000	-1,169,800,000
Property, plant and equipment, net	4,934,300,000	1,768,100,000
Depreciation expense	243,800,000
Depreciation, Depletion and Amortization, Nonproduction	280,300,000	187,000,000	145,400,000
Transmission Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	1,270,300,000	95,900,000
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	2,391,900,000	1,617,800,000
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	2,356,100,000	1,223,700,000
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	104,000,000	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	234,300,000	0
Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Change in Accounting Estimate, Financial Effect	29,400,000
Depreciation per share
Property, Plant and Equipment [Line Items]
Change in Accounting Estimate, Financial Effect	$0.18

Significant_Accounting_Policie3

Significant Accounting Policies Significant Accounting Policies (Goodwill) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 07, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill	$3,684,700,000	$3,283,100,000	$401,700,000	$401,700,000
Texas Operating Segment
Goodwill [Line Items]
Goodwill	1,168,200,000		325,400,000	325,400,000
Louisiana Operating Segment
Goodwill [Line Items]
Goodwill	786,800,000		0	0
Oklahoma Operating Segment
Goodwill [Line Items]
Goodwill	190,300,000		76,300,000	76,300,000
ORV Operating Segments
Goodwill [Line Items]
Goodwill	112,500,000		0	0
Corporate Segment
Goodwill [Line Items]
Goodwill	1,426,900,000		0	0
EnLink Midstream Holdings, LP
Goodwill [Line Items]
Increase in the Partnership's goodwill	$3,300,000,000

Significant_Accounting_Policie4

Significant Accounting Policies (Intangible Assets) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Impairments	$0	$0	$16,400,000
Accumulated Amortization	-36,500,000	0
Net Carrying Amount	533,000,000
Weighted Average Useful Life	13 years 8 months
Amortization Expense	36,500,000
Minimum
Finite-Lived Intangible Assets [Line Items]
Useful Life	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Useful Life	20 years
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	569,500,000
Accumulated Amortization	-36,500,000
Net Carrying Amount	533,000,000
Predecessor Equity
Finite-Lived Intangible Assets [Line Items]
Impairments			$16,400,000

Significant_Accounting_Policie5

Significant Accounting Policies (Intangible Amortization Expense) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Accounting Policies [Abstract]
2015	$44,500
2016	44,500
2017	44,500
2018	44,500
2019	43,600
Thereafter	311,400
Total	$533,000

Significant_Accounting_Policie6

Significant Accounting Policies (Asset Retirement Obligations) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Asset retirement obligations	$19.10	$7.70	$9.10
Asset retirement obligations	10.9	7.7
Asset Retirement Obligation, Current	$8.20

Significant_Accounting_Policie7

Significant Accounting Policies (Other Long Term Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Other Commitments [Line Items]
Contract liability	$20.30	$0
Total contract commitment
Other Commitments [Line Items]
Contract liability	$80.70

Significant_Accounting_Policie8

Significant Accounting Policies (Concentraction of Credit Risk) (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Concentration Risk [Line Items]
Allowance for Doubtful Accounts Receivable	0	0
Sales Revenue \| Devon Energy Corporation
Concentration Risk [Line Items]
Concentration Risk, Percentage	30.40%	92.20%	91.90%
Third Party [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%

Significant_Accounting_Policie9

Significant Accounting Policies (Share-Based Compensation Expense Schedule) (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$22.40	$12.80	$12.80
General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	16.9	0	0
Cost of unit-based compensation charged to operating expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$2.70	$0	$0

Acquisition_Textual_Details

Acquisition (Textual) (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended	1 Months Ended	2 Months Ended	0 Months Ended	3 Months Ended
In Millions, except Share data, unless otherwise specified	Oct. 22, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 01, 2014	Nov. 30, 2014	Dec. 31, 2014	Mar. 07, 2014	Dec. 31, 2014
Business Acquisition [Line Items]
Percentage of Voting Interests Acquired								50.00%
Total units exchanged	1,000,000	115,495,669
Business Acquisition, Transaction Costs								$51.40
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		2,504.40
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized		2,460.60
Equity interests issued and issuable	31.2
Payments to Acquire Additional Interest in Subsidiaries		12.5	0	0
Chevron Acquisition
Business Acquisition [Line Items]
Consideration Transferred					234
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							5.3
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized							4.9
Payments to Acquire Businesses, Gross						231.5
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Consideration Transferred								2,825.20
Total units exchanged								92,600,000
EnLink Midstream Holdings, LP
Business Acquisition [Line Items]
Date of Acquisition Agreement		7-Mar-14
E2 [Member]
Business Acquisition [Line Items]
Consideration Transferred	194
Payments to Acquire Businesses, Gross	163
Gulf Coast Fractionators
Business Acquisition [Line Items]
Ownership Percentage		38.75%					38.75%	38.75%	38.75%
E2 Appalachian \| Class A
Business Acquisition [Line Items]
Business acquisition additional percentage acquired									0
Payments to Acquire Additional Interest in Subsidiaries									7
E2 Appalachian \| Class B
Business Acquisition [Line Items]
Business acquisition additional percentage acquired									0
Payments to Acquire Additional Interest in Subsidiaries									$5.50
Enlink midstream, LLC
Business Acquisition [Line Items]
Limited partner interest		50.00%
Ownership interest		100.00%
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited partner interest		7.10%
Ownership interest		0.70%
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 $)	0 Months Ended	12 Months Ended	0 Months Ended
In Millions, except Share data, unless otherwise specified	Oct. 22, 2014	Dec. 31, 2014	Mar. 07, 2014	Nov. 01, 2014	Jun. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Total units exchanged	1,000,000	115,495,669
Common unit price					$41.66
Assets acquired [Abstract]
Current assets			$437.40
Property, plant and equipment			2,437.90
Assets held for disposition			569.4
Equity investment			221.5
Goodwill		3,684.70	3,283.10			401.7	401.7
Other long-term assets			1.3
Liabilities assumed:
Current liabilities			-515
Liabilities held for disposition			-1,453.70
Deferred taxes			-210.4
Long term liabilities			-101.2
Net assets acquired			4,670.30
Share Exchange Ratio			1
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net			1,841.50
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest			4,670.30
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Common Stock, Shares, Outstanding			48,000,000
Total units exchanged			48,400,000
Common unit price			$37.60
Consideration Transferred			1,822.60
Liabilities assumed:
Restricted Shares			400,000
Conversion of Stock, Shares Converted			48,400,000
Chevron Acquisition
Business Acquisition [Line Items]
Consideration Transferred				234
Assets acquired [Abstract]
Property, plant and equipment				242.2
Liabilities assumed:
Current liabilities				-10.7
Net assets acquired				231.5
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Total units exchanged			92,600,000
Common unit price			$0
Consideration Transferred			2,825.20
Liabilities assumed:
Restricted Shares			400,000
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			2,828.80
Common Unit, Outstanding			75,100,000
Preferred Units, Outstanding			17,100,000
Outstanding unit option fair value			3.9
E2 [Member] \| Enlink Midstream, Inc.
Liabilities assumed:
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			$18.90

Acquisition_Proforma_Details

Acquisition (Proforma) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Pro forma total revenues	$3,698.20	$2,597.90
Pro forma net income	240.1	102.4
Pro forma net income attributable to EnLink Midstream Partners, LP	$67.50	$70.40
Pro forma net income per common unit: Basic (usd per unit)	$0.41	$0.43
Pro forma net income per common unit: Diluted (usd per unit)	$0.41	$0.43

Affiliate_Transactions_Textual

Affiliate Transactions (Textual) (Details) (USD $)	3 Months Ended	12 Months Ended
Affiliate Transactions (Textual) (Details) (USD $)	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 07, 2014
Related Party Transaction [Line Items]
Percentage of Voting Interests Acquired					50.00%
Gross Profit	$329,800,000	$733,800,000	$403,400,000	$329,800,000
Revenues	153,900,000	2,412,700,000	179,400,000	153,900,000
Due from Affiliate, Current		120,800,000
Due to Related Parties, Current		3,000,000	0
Allocated Share-based Compensation Expense		22,400,000	12,800,000	12,800,000
Northridge Assets
Related Party Transaction [Line Items]
Gross Profit		28,400,000
Devon Energy Corporation
Related Party Transaction [Line Items]
Allocated Share-based Compensation Expense		2,800,000	12,800,000
Pension and Other Postretirement Benefit Expense		1,600,000	8,700,000	9,100,000
Devon Energy Corporation \| Sales Revenue
Related Party Transaction [Line Items]
Concentration Risk, Percentage		30.40%	92.20%	91.90%
Affiliated Entity
Related Party Transaction [Line Items]
Revenues		629,200,000
Continuing Operations \| Affiliated Entity
Related Party Transaction [Line Items]
Revenues		436,400,000	2,116,500,000	1,753,900,000
Discontinued Operations \| Affiliated Entity
Related Party Transaction [Line Items]
Revenues		10,400,000	84,600,000	152,000,000
Bridgeport
Related Party Transaction [Line Items]
Rent Expense		174,000
Oklahoma City
Related Party Transaction [Line Items]
Rent Expense		31,000
Cresson
Related Party Transaction [Line Items]
Rent Expense		$66,000
Gulf Coast Fractionators
Related Party Transaction [Line Items]
Ownership Percentage		38.75%			38.75%
EnLink Midstream Holdings, LP
Related Party Transaction [Line Items]
Date of Acquisition Agreement		7-Mar-14

Affiliate_Transactions_Affilia

Affiliate Transactions Affiliate Transactions (Predecessor's Affiliate Transactions) (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Operating revenues - affiliates	($153.90)	($2,412.70)	($179.40)	($153.90)
Net cash used in financing activities		652.4	-151.2	86.2
Capital expenditures		728.1	213.1	351.7
Net distributions from (to) related party		71.9	279.6	-23.9
Affiliated Entity
Related Party Transaction [Line Items]
Operating revenues - affiliates		-629.2
Operating expenses - affiliates		5.9	36.2	33.8
Continuing Operations \| Affiliated Entity
Related Party Transaction [Line Items]
Operating revenues - affiliates		-436.4	-2,116.50	-1,753.90
Operating expenses - affiliates		340	1,669.50	1,385.80
Net affiliate transactions		96.4	447	368.1
Capital expenditures		16.2	244.3	337.2
Other third-party transactions, net		58.9	51.5	118.7
Net third-party transactions		75.1	295.8	455.9
Net distributions from (to) related party		27.6	151.2	-87.8
Net distributions from (to) related party, non-cash		6.3	0	0
Continuing Operations \| Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party		-21.3	-151.2	87.8
Discontinued Operations
Related Party Transaction [Line Items]
Net distributions from (to) related party		4.4	128.4	63.9
Discontinued Operations \| Affiliated Entity
Related Party Transaction [Line Items]
Operating revenues - affiliates		-10.4	-84.6	-152
Operating expenses - affiliates		5	32.7	86.3
Net cash used in financing activities		0	-5.6	-1.1
Net affiliate transactions		5.4	57.5	66.8
Capital expenditures		0.6	1.1	26.5
Other third-party transactions, net		0.4	-72	-23.6
Net third-party transactions		1	-70.9	2.9
Net distributions from (to) related party		44.3	128.4	63.9
Discontinued Operations \| Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party, non-cash		$39.90	$0	$0

LongTerm_Debt_Indebtedness_Tab

Long-Term Debt (Indebtedness Table) (Details) (USD $)	12 Months Ended
Long-Term Debt (Indebtedness Table) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt	$3,200,000	$0	$0
Total outstanding debt	2,022,500,000
Line of Credit Facility, Amount Outstanding	237,000,000
Other Long-term Debt	400,000
Line of Credit
Debt Instrument [Line Items]
Total outstanding debt	237,000,000
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	0
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior Notes	399,500,000
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt	2,400,000
Senior Notes	184,400,000
8.875% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of debt	700,000
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes	553,200,000
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior Notes	349,700,000
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior Notes	$298,300,000

LongTerm_Debt_Long_Term_debt_M

Long-Term Debt (Long Term debt Maturities Schedule) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Maturities of Long-term Debt [Abstract]
2015	$0.20
2016	0.1
2017	0.1
2018	0
2019	637
Thereafter	1,362.40
Subtotal	1,999.80
Less: premium (discount)	22.7
Total outstanding debt	$2,022.50

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	12 Months Ended			9 Months Ended
Long-Term Debt (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Feb. 20, 2014	Nov. 12, 2014	Mar. 19, 2014	Sep. 20, 2014	Jul. 20, 2014	Mar. 07, 2014	Apr. 18, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Initiation Date	20-Feb-14
Long-term Debt	$2,022,500,000
Debt Instrument, Unamortized Discount (Premium), Net	22,700,000
Gain on extinguishment of debt	3,200,000	0	0
Maximum borrowing capacity	1,000,000,000				1,000,000,000
Letters of Credit Outstanding, Amount	13,900,000
Line of Credit Facility, Amount Outstanding	237,000,000
Line of Credit Facility, Remaining Borrowing Capacity	749,100,000
Other Long-term Debt	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	17,431,152
Limited partner interest	7.10%
Minimum
Debt Instrument [Line Items]
Interest Coverge Ratio	2.5
Minimum \| E2 Energy Services \| Equity Method Investee
Debt Instrument [Line Items]
Senior notes fixed interest rate	3.90%
Maximum
Debt Instrument [Line Items]
Leverage ratios	5
Conditional acquisition purchase price	50,000,000
Maximum \| E2 Energy Services \| Equity Method Investee
Debt Instrument [Line Items]
Senior notes fixed interest rate	7.00%
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	237,000,000
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	19-Mar-14
Debt Instrument, Face Amount	1,200,000,000
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Face Amount						300,000,000
Senior notes fixed interest rate	5.05%					5.05%
Senior Notes	298,300,000
Selling Priceof Debt Instrument						99.45%
Debt Instrument, Unamortized Discount (Premium), Net	0
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%
Senior Notes	349,700,000
Debt Instrument, Maturity Date	1-Apr-44
Selling Priceof Debt Instrument	99.93%
Debt Instrument, Unamortized Discount (Premium), Net	-300,000
Debt Instrument Repurchase, Tendered Offer Date	1-Oct-43
Redemption price	100.00%			100.00%
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount	450,000,000					100,000,000	450,000,000
Senior notes fixed interest rate	4.40%					4.40%	4.40%
Senior Notes	553,200,000
Debt Instrument, Maturity Date	1-Apr-24
Selling Priceof Debt Instrument	99.83%					104.01%
Debt Instrument, Unamortized Discount (Premium), Net	3,200,000
Debt Instrument Repurchase, Tendered Offer Date	1-Jan-24
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%
Senior Notes	399,500,000
Debt Instrument, Maturity Date	1-Apr-19
Selling Priceof Debt Instrument	99.85%
Debt Instrument, Unamortized Discount (Premium), Net	-500,000
Debt Instrument Repurchase, Tendered Offer Date	1-Mar-19
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	7.13%									7.13%
Senior Notes	184,400,000
Debt Instrument, Maturity Date	1-Jun-22
Long-term Debt, Fair Value										226,000,000
Debt Instrument, Unamortized Discount (Premium), Net	21,900,000									29,500,000
Debt Instrument Repurchase, Tendered Offer Date	20-Jul-14
Debt Instrument Repurchase, Tendered Amount								15,500,000	18,500,000
Debt Instrument Repurchase, Amount Paid								17,000,000	20,000,000
Gain on extinguishment of debt	2,400,000
7.125% Senior Notes due 2022 \| September Redemption
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	20-Sep-14
7.125% Senior Notes due 2022 \| Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	1-Jun-17
Redemption price	103.56%
7.125% Senior Notes due 2022 \| Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	1-Jun-18
Redemption price	102.38%
7.125% Senior Notes due 2022 \| Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	1-Jun-19
Redemption price	101.19%
7.125% Senior Notes due 2022 \| Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	1-Jun-20
Redemption price	100.00%
8.875% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount										725,000,000
Senior notes fixed interest rate										8.88%
Debt Instrument, Maturity Date	15-Feb-18
Long-term Debt, Fair Value										761,300,000
Debt Instrument, Unamortized Discount (Premium), Net										36,300,000
Debt Instrument Repurchase, Tendered Offer Date	12-Mar-14
Debt Instrument Repurchase, Tendered Amount	536,100,000
Debt Instrument Repurchase, Amount of Outstanding Tendered, Percent	74.00%
Gain on extinguishment of debt	700,000
8.875% Senior Notes due 2018 [Member] \| Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	19-Mar-14
Debt Instrument Repurchase, Amount Paid	567,400,000
8.875% Senior Notes due 2018 [Member] \| Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument Repurchase, Tendered Offer Date	18-Apr-14
Debt Instrument Repurchase, Amount Paid											200,200,000
Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity					500,000,000					125,000,000
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	250,000,000									250,000,000
Line of Credit Facility, Amount Outstanding	0
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	4.5
ENLC Credit Facility [Member] \| Eurodollar
Debt Instrument [Line Items]
Percentage Rate	1.00%

LongTerm_Debt_Percentages_Per_

Long-Term Debt (Percentages Per Annum) (Details)	12 Months Ended
Long-Term Debt (Percentages Per Annum) (Details)	Dec. 31, 2014
Standard & Poor's, BBB Rating \| Moody's, Baa1 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BBB+/Baa1
Applicable Rate Commitment Fee	0.13%
Base Rate	0.13%
Standard & Poor's, BBB Rating \| Moody's, Baa1 Rating \| Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.13%
Standard & Poor's, BBB Rating \| Moody's, Baa2 Rating
Line of Credit Facility [Line Items]
Debt Ratings	BBB/Baa2
Applicable Rate Commitment Fee	0.18%
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	0.23%
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	0.28%
Base Rate	0.63%
Standard & Poor's, BB \| Moody's, Ba1 Rating \| Eurodollar
Line of Credit Facility [Line Items]
EuroDollar Rate/Letter of Credit	1.63%
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%

LongTerm_Debt_Phantom_Interest

Long-Term Debt (Phantom Interest Rates) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Nov. 12, 2014	Mar. 19, 2014	Mar. 07, 2014
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	22.7
Line of Credit
Debt Instrument [Line Items]
EuroDollar Rate/Letter of Credit	1.90%
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior notes fixed interest rate	2.70%
Debt Instrument, Unamortized Discount (Premium), Net	-0.5
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes fixed interest rate	4.40%	4.40%	4.40%
Debt Instrument, Unamortized Discount (Premium), Net	3.2
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes fixed interest rate	5.60%
Debt Instrument, Unamortized Discount (Premium), Net	-0.3
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes fixed interest rate	7.13%			7.13%
Debt Instrument, Unamortized Discount (Premium), Net	21.9			29.5
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior notes fixed interest rate	5.05%	5.05%
Debt Instrument, Unamortized Discount (Premium), Net	0

Income_Taxes_Textuals_Details

Income Taxes (Textuals) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Mar. 07, 2014
Income Tax Contingency [Line Items]
Deferred Tax Assets, Net	$23.10	$3.20
Federal
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	48.2		146.3
Operating Loss Carryforward, Utilized in Period	98.1
State and Local
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	97.4		85.5
Operating Loss Carryforward, Utilized in Period	11.9
Deferred Tax Assets, Net	$4.20

Income_Taxes_Income_Taxes_Inco

Income Taxes Income Taxes (Income Tax Expense Benefit Tables) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current tax expense	$9	$31.50	$59.10
Deferred tax expense	67.4	35.5	-12.9
Expected income tax expense based on federal statutory rate of 35%	70.7	65.1	44.6
State income taxes, net of federal benefit and other	5.7	1.9	1.6
Total income tax expense	$76.40	$67	$46.20
Federal Statutory Income Tax Rate, Percent	35.00%

Income_Taxes_Income_Taxes_Defe

Income Taxes Income Taxes (Deferred Tax Liability) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Asset retirement obligations	$2	$2.80
State net operating loss carryforward, non current	4.2	0
Federal net operating loss carryforward, current	16.9	0.4
Total deferred tax assets	23.1	3.2
Property, plant, equipment, and intangible assets, non current	-523.5	-444.1
Other	-9.3	0
Total deferred tax liabilities	-532.8	-444.1
Deferred tax liability, net	($509.70)	($440.90)

Income_Taxes_Income_Taxes_Unre

Income Taxes Income Taxes (Unrecognized Tax Liability) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance as of December 31, 2013	$0
Unrecognized tax positions assumed in merger	3.8
Decrease due to prior year tax positions	-2
Increases due to current year tax positions	0.2
Balance as of December 31, 2014	2
Income tax penalties and interest	$0.10

Certain_Provision_of_the_Partn2

Certain Provision of the Partnership Agreement (Textual) (Details) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended	3 Months Ended
	Nov. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2014	Dec. 31, 2014
Subsidiary Sale Of Stock [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	12,075,000
Shares Issued, Price Per Share	$28.37
Proceeds from Issuance of Common Limited Partners Units	$332,300,000	$412,000,000	$0	$0
General Partner Interest
Subsidiary Sale Of Stock [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$1.09
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		$0.31
General Partner Interest \| 48% Distribution
Subsidiary Sale Of Stock [Line Items]
Incentive Distribution Percentage Levels		48.00%
Incentive Distribution, Distribution Per Unit		$0.38
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
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		7,800,000
Payments of Stock Issuance Costs		100,000
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement	$350,000,000
Partners' Capital Account, Units, Sold in Private Placement		300,000
Common Units
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit						$0.38

Earnings_per_Unit_and_Dilution2

Earnings per Unit and Dilution Computations (Details) (USD $)	0 Months Ended	3 Months Ended				12 Months Ended			9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Nov. 13, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Capital Unit [Line Items]
Distribution paid (usd per unit)	$0.23	$0.24		$0.22	$0.18
Distribution date		13-Feb-14	14-Nov-14	13-Aug-14	15-May-14
Enlink Midstream, LLC interest in net income						$90.50	$0	$0
Distributed Earnings						127.6
Undistributed Earnings, Basic						37.1
Basic common unit (usd per unit)		$0.16	$0.18	$0.18	$0.04	$0.55	$0	$0
Diluted common unit (usd per unit)		$0.16	$0.17	$0.18	$0.04	$0.55	$0	$0
Class B units
Capital Unit [Line Items]
Distribution paid (usd per unit)									$0.05
Distribution date									15-May-14
Common Unit
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income						89.9
Distributed Earnings						126.8
Undistributed Earnings, Basic						36.9
Restricted Stock Units (RSUs)
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income						0.6
Distributed Earnings						0.8
Undistributed Earnings, Basic						$0.20

Certain_Provision_of_the_Partn3

Certain Provision of the Partnership Agreement (Allocated Net Income (loss) to the General Partner) (Details) (General Partner Interest, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
General Partner Interest
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Income allocation for incentive distributions	$20.60
Unit-based compensation attributable to ENLCbs restricted units	-10.4
General Partner interest in net income	1.1
General Partner share of net income	$11.30

Earnings_per_Unit_and_Dilution3

Earnings per Unit and Dilution Computations (Unit Weighted Average Schedule) (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Capital Unit [Line Items]
Weighted Average Number Diluted Shares Outstanding Adjustment	0.3
Weighted average common shares outstanding: Basic (usd per share)	164.3
Common Unit
Capital Unit [Line Items]
Weighted Average Limited Partnership Units Outstanding, Basic	164

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$7.70	$9.10
Revisions to existing liabilities	2.2	-1.8
Liabilities acquired	8.7	0
Accretion expense	0.5	0.5	0.4
Liabilities settled	0	-0.1
Ending asset retirement obligations	19.1	7.7	9.1
Asset Retirement Obligation, Current	$8.20

Investment_in_Unconsolidated_A2

Investment in Unconsolidated Affiliate (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Distribution of earnings from equity investments	$7	$10.90	$0.40
Equity in income of equity investment	18.9	14.8	2
Investment in equity investments	270.8	61.1
Undistributed Earnings, Basic	37.1
Gulf Coast Fractionators
Schedule of Equity Method Investments [Line Items]
Distribution of earnings from equity investments	11	12	2.3
Equity in income of equity investment	17.1	14.8	2
Investment in equity investments	54.1	61.1
Undistributed Earnings, Basic	13.1
Ownership Percentage	38.75%	38.75%
Howard Energy Partners
Schedule of Equity Method Investments [Line Items]
Distribution of earnings from equity investments	12.7	0	0
Equity in income of equity investment	1.8	0	0
Investment in equity investments	216.7	0
Ownership Percentage	30.60%
Total
Schedule of Equity Method Investments [Line Items]
Distribution of earnings from equity investments	23.7	12	2.3
Equity in income of equity investment	$18.90	$14.80	$2

Employee_Incentive_Plans_Expen

Employee Incentive Plans (Expense Schedule) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$22.40	$12.80	$12.80
Amount of related income tax expense recognized in income	5.3	4.8	4.8
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	16.9	0	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	2.7	0	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	8.3	0	0
Predecessor Equity \| General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$2.80	$12.80	$12.80

Employee_Incentive_Plans_Textu

Employee Incentive Plans (Textuals) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 05, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Change in equity due to issuance of units by the Partnership (Units)	37,432
Intrinsic Value	$0.80
Employer matching contribution, percent	100.00%
Employer matching contribution, percent of employees' gross pay	6.00%
Employer 401(k) contributions	5.5
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized		11,000,000
Common Unit \| ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized	9,070,000
Pre acquisition \| ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	2 years
Pre acquisition \| ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	2 years
Post acquisition \| ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
Post acquisition \| ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
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	20.1
Unrecognized compensation costs, weighted average period for recognition	1 year 11 months
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$20.50
Unrecognized compensation costs, weighted average period for recognition	1 year 11 months

Employee_Incentive_Plans_Compe

Employee Incentive Plans (Compensation Schedule) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014
ENLK Restricted Units \| Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	0
Assumed in business combination (Units)	371,225
Granted (Units)	768,989
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-62,428
Forfeited (Units)	-55,595
Non-vested, end of period (Units)	1,022,191
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$0
Assumed in business combination (usd per share)	$30.51
Granted (usd per share)	$31.47
Vested (usd per share)	$29.40
Forfeited (usd per share)	$31.35
Non-vested, end of period (usd per share)	$31.25
Aggregate intrinsic value, end of period (in millions)	$29.70
Units withheld for payroll taxes on behalf of employees	24,314
ENLC Restricted Units
Weighted Average Grant-Date Fair Value
Units withheld for payroll taxes on behalf of employees	31,093
ENLC Restricted Units \| Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	0
Assumed in business combination (Units)	435,674
Granted (Units)	678,347
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-78,133
Forfeited (Units)	-49,416
Non-vested, end of period (Units)	986,472
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$0
Assumed in business combination (usd per share)	$37.60
Granted (usd per share)	$36.71
Vested (usd per share)	$37.64
Forfeited (usd per share)	$36.75
Non-vested, end of period (usd per share)	$37.03
Aggregate intrinsic value, end of period (in millions)	$35.10

Employee_Incentive_Plans_Intri

Employee Incentive Plans (Intrinsic and Fair Value of Units Vested) (Details) (Restricted Stock Units (RSUs), USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$1.80
Fair value of units vested	1.9
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	3.1
Fair value of units vested	$2.90

Derivatives_Summary_of_Derivat

Derivatives (Summary of Derivative Income Expense) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives that are not designated for hedge accounting	$22.10	$0	$0
Net gains related to commodity swaps	22.1	0	0
Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Settlement losses on derivatives	3.6
Commodity Swap
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives that are not designated for hedge accounting	22.4
Settlement losses on derivatives	-0.3
Net gains related to commodity swaps	$22.10

Derivatives_Schedule_of_Deriva

Derivatives (Schedule of Derivative Assets Liabilities) (Details) (Not Designated as Hedging Instrument, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of derivative assets b current	$16.70
Fair value of derivative assets b long term	10
Fair value of derivative liabilities b current	-3
Fair value of derivative liabilities b long term	-2
Net fair value of derivatives	$21.70

Derivatives_Derivatives_Outsta

Derivatives (Derivatives Outstanding) (Details) (Not Designated as Hedging Instrument, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Derivative [Line Items]
Net fair value of derivatives	$21.70
Short Contracts \| Liquids
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	57,000,000
Net fair value of derivatives	26.3
Short Contracts \| Gas
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,400,000
Net fair value of derivatives	0.3
Long Contracts \| Liquids
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	45,400,000
Net fair value of derivatives	-4.5
Long Contracts \| Gas
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,100,000
Net fair value of derivatives	($0.40)

Derivatives_Details_Textuals

Derivatives (Details Textuals) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum counterparty loss	$26.70
Maximum counterparty loss with netting feature	$21.70

Derivatives_Derivatives_Other_

Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) (Market Approach Valuation Technique, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Derivative [Line Items]
Derivative instruments at fair value	$21.70
Less than one year
Derivative [Line Items]
Derivative instruments at fair value	13.7
One to two years
Derivative [Line Items]
Derivative instruments at fair value	8
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) (Fair Value, Inputs, Level 2, Commodity Swap, Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	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	$21.70

Fair_Value_Measurement_Fair_Va

Fair Value Measurement (Fair Value of Financial Instrument) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$2,022.50
Carrying (Reported) Amount, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	2,022.50
Obligations under capital lease	20.3
Estimate of Fair Value, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	2,026.10
Obligations under capital lease	$19.80

Fair_Value_Measurement_Details

Fair Value Measurement (Details Textuals) (USD $)	Dec. 31, 2014	Nov. 12, 2014	Mar. 19, 2014	Mar. 07, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$237,000,000
Long-term Debt	2,022,500,000
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior Notes	399,500,000
Senior notes fixed interest rate	2.70%
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes	553,200,000
Senior notes fixed interest rate	4.40%	4.40%	4.40%
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior Notes	349,700,000
Senior notes fixed interest rate	5.60%
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior Notes	298,300,000
Senior notes fixed interest rate	5.05%	5.05%
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes	$184,400,000
Senior notes fixed interest rate	7.13%			7.13%

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Aug. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015		$11.60
2016		9.2
2017		6.6
2018		11.5
2019		9
Thereafter		71.2
Total Operating Leases		119.1
Gain on litigation settlement	$6.10	$6.10	$0	$0

Segment_Information_Details

Segment Information (Details) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Aug. 31, 2014	Mar. 31, 2012	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Mar. 07, 2014
Segment Reporting Information [Line Items]
Revenues		$153.90	$2,412.70		$179.40		$153.90
Revenues - affiliates		1,753.90	1,065.60		2,116.50		1,753.90
Purchased gas, NGLs, condensate and crude oil		-1,428.10	-2,494.50	[1]	-1,736.30	[1]	-1,428.10	[1]
Operating expenses		-149.9	-278.2	[2]	-156.2	[2]	-149.9	[2]
Gain on litigation settlement	6.1		6.1		0		0
Depreciation, amortization and impairments			-280.3		-187
Loss on derivatives			22.1		0		0
Segment profit		329.8	733.8		403.4		329.8
Depreciation, amortization and impairments			-280.3		-187		-161.8
Goodwill			3,684.70		401.7		401.7		3,283.10
Capital expenditures			728.1		213.1		351.7
Segment identifiable assets			10,097.30		2,309.80
Texas Operating Segment
Segment Reporting Information [Line Items]
Revenues			284.3		129.3		124.4
Revenues - affiliates			782.9		1,419.80		1,232.80
Purchased gas, NGLs, condensate and crude oil			-490.9		-1,130.40		-983.3
Operating expenses			-145.4		-121.2		-119.8
Gain on litigation settlement			0
Depreciation, amortization and impairments			-125.9		-110.6
Loss on derivatives			0
Segment profit			430.9		297.5		254.1
Depreciation, amortization and impairments							-98.3
Goodwill			1,168.20		325.4		325.4
Capital expenditures			271		147		142.4
Segment identifiable assets			3,303		1,460
Louisiana Operating Segment
Segment Reporting Information [Line Items]
Revenues			1,852.30		0		0
Revenues - affiliates			73.2		0		0
Purchased gas, NGLs, condensate and crude oil			-1,754.20		0		0
Operating expenses			-68.2		0		0
Gain on litigation settlement			6.1
Depreciation, amortization and impairments			-69.3		0
Loss on derivatives			0
Segment profit			109.2		0		0
Depreciation, amortization and impairments							0
Goodwill			786.8		0		0
Capital expenditures			273.1		0		0
Segment identifiable assets			3,316.50		0
Oklahoma Operating Segment
Segment Reporting Information [Line Items]
Revenues			14.8		50.1		29.5
Revenues - affiliates			304		696.7		521.1
Purchased gas, NGLs, condensate and crude oil			-142.5		-605.9		-444.8
Operating expenses			-28.6		-35		-30.1
Gain on litigation settlement			0
Depreciation, amortization and impairments			-49.4		-76.4
Loss on derivatives			0
Segment profit			147.7		105.9		75.7
Depreciation, amortization and impairments							-63.5
Goodwill			190.3		76.3		76.3
Capital expenditures			17.1		66.1		209.3
Segment identifiable assets			892.8		777.1
ORV Operating Segments
Segment Reporting Information [Line Items]
Revenues			261.3		0		0
Revenues - affiliates			0		0		0
Purchased gas, NGLs, condensate and crude oil			-201.4		0		0
Operating expenses			-36		0		0
Gain on litigation settlement			0
Depreciation, amortization and impairments			-33		0
Loss on derivatives			0
Segment profit			23.9		0		0
Depreciation, amortization and impairments							0
Goodwill			112.5		0		0
Capital expenditures			153		0		0
Segment identifiable assets			762.5		0
Corporate Segment
Segment Reporting Information [Line Items]
Revenues			0		0		0
Revenues - affiliates			-94.5		0		0
Purchased gas, NGLs, condensate and crude oil			94.5		0		0
Operating expenses			0		0		0
Gain on litigation settlement			0
Depreciation, amortization and impairments			-2.7		0
Loss on derivatives			22.1
Segment profit			22.1		0		0
Depreciation, amortization and impairments							0
Goodwill			1,426.90		0		0
Capital expenditures			13.9		0		0
Segment identifiable assets			$1,822.50		$72.70

[1]	Includes $354.3 million, $1,588.2 million and $1,310.3 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate purchased gas.
[2]	Includes $5.9 million, $36.2 million and $33.8 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate operating expenses.

Segment_Information_Reconcilia

Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) (USD $)	3 Months Ended									12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting [Abstract]
Segment profits									$329.80	$733.80		$403.40		$329.80
General and administrative expenses										-97.3	[1]	-45.1	[1]	-41.7	[1]
Depreciation, amortization and impairments										-280.3		-187		-161.8
Gain on sale of property and other assets										0.1		0		0
Operating income	$101.10	$89.30	$91.90	$74	$44.70	$48.10	$42.60	$35.90		$356.30		$171.30		$126.30

[1]	Includes $11.6 million, $45.1 million and $41.7 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate general and administrative expenses.

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$995.20	$855	$927.20	$723	$602.80	$578.20	$588	$526.90	$3,500.40	$2,295.90	$1,907.80
Operating income	101.1	89.3	91.9	74	44.7	48.1	42.6	35.9	356.3	171.3	126.3
Net Income (Loss) Attributable to Noncontrolling Interest	46.2	37.7	35.7	7.1					126.7	0	0
Net income attributable to Enlink Midstream, LLC	$26.10	$28.80	$28.80	$42.30	$23	$30.30	$32.80	$29.40	$126	$115.50	$75.80
Income per common unit-basic (usd per unit)	$0.16	$0.18	$0.18	$0.04					$0.55	$0	$0
Income per common unit-diluted (usd per unit)	$0.16	$0.17	$0.18	$0.04					$0.55	$0	$0

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 07, 2014
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Operating revenues	$6.80	$42.10	$53.10
Operating revenues - affiliates	10.5	84.6	152
Total operating revenues	17.3	126.7	205.1
Operating expenses:	15.7	130.3	213.2
Total operating expenses	15.7	130.3	213.2
Income (loss) before income taxes	1.6	-3.6	-8.1
Income tax provision (benefit)	0.6	-1.3	-2.9
Net income (loss)	1	-2.3	-5.2
Net income attributable to non-controlling interest	0	-1.3	-1.1
Net income (loss) including non-controlling interest	1	-3.6	-6.3
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Inventories		0.2
Other current assets		0.2
Total current assets		0.4
Property, plant & equipment		72.3
Total assets	0	72.7
Accounts payable		3.2
Other current liabilities		1.1
Total current liabilities		4.3
Asset retirement obligations		7.1
Deferred income taxes		25.3
Other long-term liabilities		0.3
Total liabilities		$37
Gulf Coast Fractionators
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership Percentage	38.75%			38.75%

Subsequent_Events_Subsequent_E

Subsequent Events Subsequent Events (Fixed Debt Obligations) (Details) (USD $)	0 Months Ended
Share data in Millions, unless otherwise specified	Jan. 31, 2015	Feb. 17, 2015	Dec. 31, 2014	Feb. 20, 2014	Feb. 05, 2015
Subsequent Event [Line Items]
Maximum borrowing capacity			$1,000,000,000	$1,000,000,000
Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity					1,500,000,000
Subsequent Event \| LPC Crude Oil Marketing LLC
Subsequent Event [Line Items]
Consideration Transferred	100,000,000
Midstream Holdings \| EMH Drop Down \| Affiliated Entity \| Acacia \| Subsequent Event
Subsequent Event [Line Items]
Cumulative Percentage Ownership after All Transactions		25.00%
Midstream Holdings \| EMH Drop Down \| Affiliated Entity \| EnLink Midstream Holdings, LP \| Subsequent Event
Subsequent Event [Line Items]
Cumulative Percentage Ownership after All Transactions		75.00%
Midstream Holdings \| EMH Drop Down \| Affiliated Entity \| EnLink Midstream LP \| Acacia \| Subsequent Event \| EnLink Midstream Holdings, LP
Subsequent Event [Line Items]
Ownership Interest Transferred		25.00%
Amounts of Transaction		925,000,000
Class D Common Unit \| Midstream Holdings \| EMH Drop Down \| Affiliated Entity \| EnLink Midstream LP \| Acacia \| Subsequent Event \| EnLink Midstream Holdings, LP
Subsequent Event [Line Items]
Amounts of Transaction, Shares		31.6

Condensed_Financial_Informatio1

Condensed Financial Information of Parent Company Only Condensed Balance Sheets - Parent Only (Details) (USD $)	Dec. 31, 2014	Mar. 07, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 07, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$68.40		$0	$15.60	$8.10
Accounts receivable	139		0.4
Related party	120.8		0
Total current assets	646.9		78.9
Goodwill	3,684.70	3,283.10	401.7	401.7
Investment in equity investments	270.8		61.1
Other assets, net	17.6		0
Total assets	10,097.30		2,309.80
Other current liabilities	92.1		38.8
Total current liabilities	480.4		77.5
Deferred tax liability	526.6		440.9
Members' equity	2,774.30		0
Total members' equity	6,971.10		1,783.70	2,002	1,901.30
Total liabilities and members' equity	10,097.30		2,309.80
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	58.8		0
Accounts receivable	0
Related party	2.4
Prepaid expenses and other	1.1
Total current assets	62.3
Goodwill	1,426.90
Investment in equity investments	1,723
Other assets, net	0.9
Total assets	3,213.10
Other current liabilities	2.2
Total current liabilities	2.2
Deferred tax liability	436.6
Members' equity	2,774.30
Total members' equity	2,774.30
Total liabilities and members' equity	$3,213.10

Condensed_Financial_Informatio2

Condensed Financial Information of Parent Company Only Condensed Statement of Operations - Parent Only (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Income from equity investments									$18.90		$14.80		$2
Total revenues	995.2	855	927.2	723	602.8	578.2	588	526.9	3,500.40		2,295.90		1,907.80
General and administrative expenses									97.3	[1]	45.1	[1]	41.7	[1]
Total operating costs and expenses									3,144.10		2,124.60		1,781.50
Operating income	101.1	89.3	91.9	74	44.7	48.1	42.6	35.9	356.3		171.3		126.3
Interest and other income									-28.2		14.8		2
Income from continuing operations before non-controlling interest and income taxes									328.1		186.1		128.3
Income tax provision									76.4		67		46.2
Net income									252.7		115.5		75.8
Basic common unit (usd per unit)	$0.16	$0.18	$0.18	$0.04					$0.55		$0		$0
Diluted common unit (usd per unit)	$0.16	$0.17	$0.18	$0.04					$0.55		$0		$0
Weighted average common shares outstanding: Basic (usd per share)									164.3
Parent Company
Condensed Financial Statements, Captions [Line Items]
Income from equity investments									185.7
Total revenues									185.7
General and administrative expenses									3
Total operating costs and expenses									3
Operating income									182.7
Interest and other income									-2.4
Income from continuing operations before non-controlling interest and income taxes									180.3
Income tax provision									-54.3
Net income									$126
Basic common unit (usd per unit)									$0.55
Diluted common unit (usd per unit)									$0.55
Weighted average common shares outstanding: Basic (usd per share)									164

[1]	Includes $11.6 million, $45.1 million and $41.7 million for the year ended December 31, 2014, 2013 and 2012, respectively, of affiliate general and administrative expenses.

Condensed_Financial_Informatio3

Condensed Financial Information of Parent Company Only Condensed Statement of Cash Flows - Parent Only (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income	$252.70	$115.50	$75.80
Adjustments to reconcile net income to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Equity in income of equity investment	-18.9	-14.8	-2
Deferred tax expense	67.4	35.5	-12.9
Stock-based compensation	19.6	0	0
Amortization of debt issue cost	1.9	0	0
Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other	-98.1	0	0
Accounts payable, and other accrued liabilities	-17.3	-8.6	-17.5
Net cash provided by operating activities	457.3	330.3	209.7
Cash flows from investing activities:
Acquisition of business	-5.7	0	-17.1
Distribution from limited liability company in excess of earnings	10.9	1.1	1.9
Net cash used in investing activities	-1,041.30	-243.2	-352.4
Cash flows from financing activities:
Proceeds from borrowings	3,367.80	0	0
Payments on borrowings	-2,792.70	0	0
Debt refinancing cost	-19.7	0	0
Conversion of restricted units, net of units withheld for taxes	-1.1	0	0
Distribution to members	-89	0	0
Net cash provided by (used in) financing activities	652.4	-151.2	86.2
Net increase (decrease) in cash and cash equivalents	68.4	-15.6	7.5
Cash and cash equivalents, beginning of period	0	15.6	8.1
Cash and cash equivalents, end of period	68.4	0	15.6
Parent Company
Cash flows from operating activities:
Net income	126
Adjustments to reconcile net income to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Equity in income of equity investment	-185.7
Deferred tax expense	52
Stock-based compensation	0.2
Amortization of debt issue cost	0.2
Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other	-1.5
Accounts payable, and other accrued liabilities	-13.5
Net cash provided by operating activities	-22.3
Cash flows from investing activities:
Proceeds from sale of investment	163
Acquisition of business	-16.7
Distribution from limited liability company in excess of earnings	194.9
Acquisition of non-controlling interest	-93.5
Net cash used in investing activities	247.7
Cash flows from financing activities:
Proceeds from borrowings	216.3
Payments on borrowings	-291.5
Debt refinancing cost	-1.1
Conversion of restricted units, net of units withheld for taxes	-1.3
Distribution to members	-89
Net cash provided by (used in) financing activities	-166.6
Net increase (decrease) in cash and cash equivalents	58.8
Cash and cash equivalents, beginning of period	0
Cash and cash equivalents, end of period	58.8
Loss from issuance of Partnership units	$1.80