10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the quarterly period ended June 30, 2015

OR

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from               to               

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter) 

Delaware	46-4108528
(State of organization)	(I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS RD.
DALLAS, TEXAS	75201
(Address of principal executive offices)	(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

As of July 24, 2015, the Registrant had 164,231,749 common units outstanding.

TABLE OF CONTENTS

Item	Description	Page
	PART I—FINANCIAL INFORMATION
1.	Financial Statements	3
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
3.	Quantitative and Qualitative Disclosures About Market Risk	53
4.	Controls and Procedures	55
	PART II—OTHER INFORMATION
1.	Legal Proceedings	55
1A.	Risk Factors	56
6.	Exhibits	57

2

ENLINK MIDSTREAM, LLC

Condensed Consolidated Balance Sheets

	June 30, 2015		December 31, 2014
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	72.0	$	68.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.4	67.4		139.0
Accrued revenue and other	379.6		253.3
Related party	110.8		121.6
Fair value of derivative assets	14.0		16.7
Natural gas and NGLs inventory, prepaid expenses and other	70.9		48.8
Total current assets	714.7		647.8
Property and equipment, net of accumulated depreciation of $1,585.7 and $1,426.3,     respectively	5,550.5		5,042.8
Intangible assets, net of accumulated amortization of $66.3 and $36.5, respectively	840.5		533.0
Goodwill	3,731.2		3,684.7
Fair value of derivative assets	4.9		10.0
Investments in unconsolidated affiliates	261.2		270.8
Other assets, net	25.5		17.6
Total assets	$	11,128.5	$	10,206.7
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	39.1	$	121.8
Accounts payable to related party	21.6		3.0
Accrued gas, NGLs, condensate and crude oil purchases	316.3		204.5
Fair value of derivative liabilities	3.5		3.0
Other current liabilities	163.0		152.3
Total current liabilities	543.5		484.6
Long-term debt	2,827.2		2,022.5
Fair value of derivative liabilities	0.8		2.0
Asset retirement obligation	12.6		12.4
Other long-term liabilities	75.2		83.8
Deferred tax liability	543.7		526.6
Redeemable non-controlling interest	6.9		—
Members’ equity
Members' equity	2,743.6		2,774.3
Non-controlling interest	4,375.0		4,196.8
Net Devon investment	—		103.7
Total members' equity	7,118.6		7,074.8
Commitment and Contingencies (Note 15)
Total liabilities and members’ equity	$	11,128.5	$	10,206.7

See accompanying notes to condensed consolidated financial statements.

3

ENLINK MIDSTREAM, LLC

Condensed Consolidated Statements of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited) (In millions, except per unit amounts)
Revenues:
Product sales	$	956.2		$	687.9		$	1,626.9		$	901.3
Product sales - affiliates	31.7			—			47.9			436.4
Midstream services	135.9			67.1			238.3			86.2
Midstream services - affiliates	149.5			173.8			300.5			229.3
Gain (loss) on derivative activity	1.2			(1.6		)	1.4			(2.9		)
Total revenues	1,274.5			927.2			2,215.0			1,650.3
Operating costs and expenses:
Cost of sales (1)	968.2			661.9			1,625.6			1,200.8
Operating expenses (2)	109.1			73.9			207.6			120.6
General and administrative (3)	28.1			26.6			70.8			42.5
Depreciation and amortization	97.7			75.0			189.0			123.5
Total operating costs and expenses	1,203.1			837.4			2,093.0			1,487.4
Operating income	71.4			89.8			122.0			162.9
Other income (expense):
Interest expense, net of interest income	(22.6		)	(14.1		)	(41.7		)	(19.5		)
Equity in income of equity investment	5.9			4.5			9.7			8.7
Gain on extinguishment of debt	—			0.8			—			0.8
Other income (expense)	0.1			(0.1		)	0.5			(0.8		)
Total other expense	(16.6		)	(8.9		)	(31.5		)	(10.8		)
Income from continuing operations before non-controlling interest and income taxes	54.8			80.9			90.5			152.1
Income tax provision	(10.2		)	(18.5		)	(20.9		)	(42.2		)
Net income from continuing operations	44.6			62.4			69.6			109.9
Discontinued operations:
Income from discontinued operations, net of tax	—			—			—			1.0
Discontinued operations, net of tax	—			—			—			1.0
Net income	44.6			62.4			69.6			110.9
Net income attributable to the non-controlling interest	28.4			35.7			36.4			42.8
Net income attributable to EnLink Midstream, LLC	$	16.2		$	26.7		$	33.2		$	68.1
Predecessor interest in net income (4)	$	—		$	—		$	—		$	35.5
Devon investment interest in net income	$	1.7		$	(2.1	)	$	2.4		$	(3.0	)
EnLink Midstream, LLC interest in net income	$	14.5		$	28.8		$	30.8		$	35.6
Net income attributable to EnLink Midstream, LLC per unit:
Basic per common unit	$	0.09		$	0.18		$	0.19		$	0.22
Diluted per common unit	$	0.09		$	0.18		$	0.19		$	0.22

(1) Includes $32.0 million for the three months ended June 30, 2015 and $39.9 million and $325.8 million for the six months ended June 30, 2015 and 2014, respectively, of affiliate cost of sales.

(2) Includes $0.2 million for the three and six months ended June 30, 2015 and $5.9 million for the six months ended June 30, 2014 of affiliate operating expenses.

(3) Includes $0.1 million for the three and six months ended June 30, 2015 and $1.1 million and $9.6 million for the three and six months ended June 30, 2014, respectively, of affiliate general and administrative expenses.

(4) Represents net income attributable to the Predecessor for the period prior to March 7, 2014.

See accompanying notes to condensed consolidated financial statements.

4

ENLINK MIDSTREAM, LLC

Consolidated Statement of Changes in Members’ Equity

Six Months Ended June 30, 2015

	Common Units				Net Devon Investment			Non-Controlling Interest						Redeemable Non-controlling Interest (Temporary Equity)
	$			Units	$			$			Total			$
	(Unaudited)
	(In millions)
Balance, December 31, 2014	$	2,774.3		164.1	$	103.7		$	4,196.8		$	7,074.8		$	—
Unit-based compensation	11.0			—	—			10.5			21.5			—
Issuance of units by the Partnership	—			—	—			364.1			364.1			—
Conversion of restricted units for common, net of units withheld for taxes	(2.8		)	0.1	—			—			(2.8		)	—
Non-controlling partner's impact of conversion of restricted units	—			—	—			(2.5		)	(2.5		)	—
Change in equity due to issuance of units by the     partnership	8.5			—	—			(13.5		)	(5.0		)	—
Non-controlling interest distributions	—			—	—			(175.7		)	(175.7		)	—
Non-controlling interest contribution	—			—	—			7.3			7.3			—
Distributions to members	(79.3		)	—	—			—			(79.3		)	—
Tax benefit from vesting of restricted units	1.1			—	—			—			1.1			—
Adjustment related to mandatory redemption of E2 non-controlling interest	—			—	—			(5.4		)	(5.4		)	—
Redeemable non-controlling interest	—			—	—			(6.9		)	(6.9		)	6.9
Contribution from Devon to the Partnership	—			—	26.6			2.2			28.8			—
Distribution to Devon in connection with acquisition     of net assets	—			—	(132.7		)	(38.3		)	(171.0		)	—
Net income	30.8			—	2.4			36.4			69.6			—
Balance, June 30, 2015	$	2,743.6		164.2	$	—		$	4,375.0		$	7,118.6		$	6.9

See accompanying notes to condensed consolidated financial statements.

5

ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows

	Six Months Ended June 30,
	2015			2014
	(Unaudited) (In millions)
Cash flows from operating activities:
Net income from continuing operations	$	69.6		$	109.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	189.0			123.5
Accretion expense	0.3			0.3
Gain on extinguishment of debt	—			(0.8		)
Deferred tax expense	17.8			41.5
Non-cash unit-based compensation	21.5			7.0
(Gain) loss on derivatives recognized in net income	(5.0		)	2.9
Cash settlements on derivatives	11.3			(0.9		)
Amortization of debt issue costs	1.5			0.4
Amortization of premium on notes	(1.5		)	(1.0		)
Redeemable non-controlling interest expense	(3.3		)	—
Distribution of earnings from equity investment	10.3			0.7
Equity in income from equity investments	(9.7		)	(8.7		)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	57.3			(10.5		)
Natural gas and NGLs inventory, prepaid expenses and other	(26.6		)	(15.3		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(55.5		)	(45.8		)
Net cash provided by operating activities	277.0			203.2
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(349.2		)	(336.7		)
Acquisition of business, net of cash acquired	(324.8		)	(126.0		)
Proceeds from sale of property	0.1			—
Investment in limited liability company	—			(5.7		)
Distribution from equity investment company in excess of earnings	8.9			5.0
Net cash used in investing activities	(665.0		)	(463.4		)
Cash flows from financing activities:
Proceeds from borrowings	2,327.4			1,732.2
Payments on borrowings	(1,521.2		)	(1,490.2		)
Payments on capital lease obligations	(1.6		)	(1.2		)
Increase (decrease) in drafts payable	(12.4		)	8.6
Debt financing costs	(9.5		)	(7.4		)
Conversion of restricted units, net of units withheld for taxes	(2.8		)	—
Conversion of Partnership's restricted units, net of units withheld for taxes	(2.5		)	—
Proceeds from issuance of Partnership's common units	4.1			19.9
Proceeds from exercise of Partnership unit options	—			0.3
Distribution to non-controlling partners	(175.7		)	(45.8		)
Distribution to Members	(79.3		)	(14.7		)
Contribution from Devon	28.8			95.3
Distribution to Devon for net assets acquired (Note 3)	(171.0		)	—
Contributions by non-controlling interest	7.3			1.2
Distributions to Predecessor	—			(22.1		)
Net cash provided by financing activities	391.6			276.1
Cash flow from discontinued operations:
Net cash provided by operating activities	—			5.0
Net cash used in investing activities	—			(0.6		)
Net cash used in financing activities – net distributions to        Devon and non-controlling interests	—			(4.4		)
Net cash provided by discontinued operations	—			—
Net increase in cash and cash equivalents	3.6			15.9
Cash and cash equivalents, beginning of period	68.4			—
Cash and cash equivalents, end of period	$	72.0		$	15.9
Cash paid for interest	$	44.4		$	17.1
Cash paid for income taxes	$	13.4		$	6.9

See accompanying notes to condensed consolidated financial statements.

6

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements

June 30, 2015

(Unaudited)

(1) General

In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” and “us,” or like terms, are sometimes used as references to EnLink Midstream, LLC and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP and Midstream Holdings, together with their consolidated subsidiaries. “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization 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. ("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 Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.3% limited partner interest in the Partnership as of June 30, 2015 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). At the conclusion of the mergers, Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 common units to a wholly-owned subsidiary of Devon, which represents approximately 70% of the outstanding limited liability company interests in ENLC. Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to the Partnership in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.6% limited partner interest in the Partnership as of June 30, 2015. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the "May Transferred Interests") to the Partnership in a drop down transaction (the "May EMH Drop Down" and together with the February EMH Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.2% limited partner interest in the Partnership as of June 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See Note (3) - Acquisitions for further discussion.

Our assets consist of equity interests in the Partnership. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. As of June 30, 2015, our interests in the Partnership consist of the following:

•68,248,199 common units representing an aggregate 26.1% limited partner interest in the Partnership; and

• 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

7

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. The Partnership's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and its south Louisiana processing plants to its fractionators in south Louisiana. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of arrangements. The Partnership'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. The Partnership also provides a variety of crude oil and condensate services which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucking facilities as well as brine disposal services.

(2) Significant Accounting Policies

(a) Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) 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. 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 the Company, as well as the Company'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.

On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to "Devon investment interest in net income" on the Company's Condensed Consolidated Statements of Operations.

(b) Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services through various contractual arrangements which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is

8

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal, or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the consolidated statements of operations as follows:

• Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above.

• Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Condensed Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holders' share of net income or loss and distributions).

(d) Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the six months ended June 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

9

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(3) Acquisitions

Chevron Acquisition

Effective November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the equity interests (all of which were voting) in certain entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Property, plant and equipment	$	225.3
Intangibles	13.0
Liabilities assumed:
Current liabilities	(6.8		)
Total identifiable net assets	$	231.5

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 20 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. The Partnership incurred $0.4 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 1, 2015 to June 30, 2015, the Partnership recognized $16.0 million of revenues and $0.1 million of net income related to the assets acquired.

LPC Acquisition

On January 31, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million ($78.9 million, net of cash acquired). The transaction was accounted for using the acquisition method.

10

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $21.1 million in cash)	$	107.4
Property, plant and equipment	29.8
Intangibles	43.2
Goodwill	29.6
Liabilities assumed:
Current liabilities	(106.0		)
Deferred tax liability	(4.0		)
Total identifiable net assets	$	100.0

The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Crude and Condensate segment and is non-deductible for tax purposes.

The Partnership incurred $0.2 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 31, 2015 to June 30, 2015, the Partnership recognized $559.6 million of revenues and $1.6 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $602.1 million. The purchase price consisted of $242.1 million in cash ($232.5 million, net of cash acquired), 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $9.6 million in cash)	$	26.2
Property, plant and equipment	302.1
Intangibles	281.0
Goodwill	16.9
Liabilities assumed:
Current liabilities	(24.1		)
Total identifiable net assets	$	602.1

11

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment and is non-deductible for tax purposes.

The Partnership incurred $3.0 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from March 17, 2015 to June 30, 2015, the Partnership recognized $61.5 million of revenues and $4.1 million of net loss related to the assets acquired.

VEX Pipeline Drop Down

On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford shale in south Texas, together with 100% of the equity interests (all of which were voting) in certain entities, from Devon in a drop down transaction (the "VEX Drop Down"). The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX Interests were recorded on the Partnership's books at historical cost on the date of transfer of $132.7 million. The difference between the historical cost of the net assets and consideration given was $38.3 million and is recognized as a distribution to Devon. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon.

The following tables present the impact of the VEX Drop Down as presented in the Company's historical Condensed Consolidated Statements of Operations for the six months ended June 30, 2015 and three and six months ended June 30, 2014:

	Six Months Ended June 30, 2015
	Company Historical		VEX		Combined
	(in millions)
Revenues	$	2,210.8	$	4.2	$	2,215.0
Net income (loss)	$	67.2	$	2.4	$	69.6
Net income attributable to non-controlling interest	$	36.4	$	—	$	36.4
Net income attributable to EnLink Midstream, LLC	$	30.8	$	2.4	$	33.2
EnLink Midstream, LLC interest in net income	$	30.8	$	—	$	30.8

	Three Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	927.2	$	—		$	927.2
Net income (loss)	$	64.5	$	(2.1	)	$	62.4
Net income attributable to non-controlling interest	$	35.7	$	—		$	35.7
Net income attributable to EnLink Midstream, LLC	$	28.8	$	(2.1	)	$	26.7
EnLink Midstream, LLC interest in net income	$	28.8	$	—		$	28.8

12

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

	Six Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	1,650.3	$	—		$	1,650.3
Net income (loss)	$	113.9	$	(3.0	)	$	110.9
Net income attributable to non-controlling interest	$	42.8	$	—		$	42.8
Net income attributable to EnLink Midstream, LLC	$	71.1	$	(3.0	)	$	68.1
EnLink Midstream, LLC interest in net income (1)	$	35.6	$	—		$	35.6

(1) Represents net income for the period from March 7, 2014 through June 30, 2014.

Devon Merger

On March 7, 2014, EMI merged with and into a wholly-owned subsidiary of the Company, and 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 Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. As of June 30, 2015, the Company, through its ownership of EMI, owned approximately 5.3% of the outstanding limited partner interests in the Partnership and owned 100.0% of the General Partner. The Company, through its ownership of 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 was 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.

For the period from March 7, 2014 to June 30, 2014, the Company recognized $968.8 million of revenues and $26.5 million of net loss related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, and VEX Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Pro forma financial information associated with the business combination and acquisitions is reflected below.

13

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

		Three Months Ended June 30,		Six Months Ended   June 30,
		2014		2015		2014
	(in millions)
Pro forma total revenues (1)		$	1,453.4	$	2,337.2	$	2,834.6
Pro forma net income		$	55.2	$	64.7	$	74.0
Pro forma net income attributable to EnLink Midstream, LLC		$	25.3	$	31.0	$	42.7
Pro forma net income per common unit:
Basic		$	0.17	$	0.18	$	0.28
Diluted		$	0.17	$	0.18	$	0.28

(1) On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company evaluates goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. 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 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 performed its annual impairment test of goodwill as of the fourth quarter of 2014. 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.

	June 30, 2015		December 31, 2014
	(in millions)
Texas	$	1,185.0	$	1,168.2
Louisiana	786.8		786.8
Oklahoma	190.3		190.3
Crude and Condensate	142.1		112.5
Corporate	1,427.0		1,426.9
Total	$	3,731.2	$	3,684.7

The change in goodwill is related to an increase of $29.6 million attributable to the acquisition of LPC, which is included in the Crude and Condensate segment, and an increase of $16.9 million attributable to the acquisition of Coronado, which is included in the Texas segment. See Note 3-Acquisitions for further discussion.

Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from five to twenty years.

14

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The following table represents the Partnership's total purchased intangible assets for the periods stated (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
June 30, 2015
Customer relationships	$	906.8	$	(66.3	)	$	840.5
December 31, 2014
Customer relationships	$	569.5	$	(36.5	)	$	533.0

The weighted average amortization period for intangible assets is 11.2 years. Amortization expense for intangibles was approximately $18.2 million and $11.3 million for the three months ended June 30, 2015 and 2014, respectively, and $29.7 million and $13.0 million for the six months ended June 30, 2015 and 2014, respectively.

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

2015 (remaining)	$	33.2
2016	66.4
2017	66.4
2018	66.3
2019	65.5
Thereafter	542.7
Total	$	840.5

(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and six months ended June 30, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 14.2% and 15.7% of the Partnership's revenues for the three and six months ended June 30, 2015, respectively, and 18.7% and 40.3% for the three and six months ended June 30, 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $112.2 million as of June 30, 2015 and $121.6 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $21.6 million as of June 30, 2015 and $3.0 million as of December 31, 2014. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

Gathering, Processing and Transportation Agreements with Devon

As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  On January 1, 2014, in connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings ("EnLink Midstream Services"), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon ("Gas Services"), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering systems in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has

15

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.

Effective December 1, 2014, Gas Services assigned one of its 10-year gathering and processing agreements to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, beginning on December 1, 2014, Linn Energy began performing Gas Services' obligations under the applicable agreement, which relates to production dedicated to our Northridge assets in southeastern Oklahoma and remains in full force and effect.

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon.  The terms of these agreements vary, but the agreements expire between July 2015 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee.  These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline.

Transition Services Agreement

In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.1 million for the three and six months ended June 30, 2015 and $1.1 million and $1.3 million for the three and six months ended June 30, 2014, respectively. We received $0.2 million from Devon under the transition services agreement for the six months ended June 30, 2015. Substantially all services under the transition services agreement were completed during 2014.

EMH Drop Down to Partnership

On February 17, 2015, Acacia contributed the February Transferred Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

16

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015, which was the first business day following the record date for distribution payments with respect to the distribution for the quarter ended June 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

E2 Drop Down to Partnership

On October 22, 2014, EMI contributed its equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) to the Partnership in a drop down transaction (the "E2 Drop Down"). The total consideration for the transaction was approximately $194.0 million, including a cash payment of $163.0 million and the issuance of approximately 1.0 million Partnership units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the Partnership's units).

Predecessor Affiliate Transactions

Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates.

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

	Six Months Ended June 30, 2014
Continuing Operations:
Revenues - affiliates	$	(436.4	)
Operating cost and expenses - affiliates	340.0
Net affiliate transactions	(96.4		)
Capital expenditures	21.3
Other third-party transactions, net	53.0
Net third-party transactions	74.3
Net cash distributions to Devon - continuing operations	(22.1		)
Non-cash distribution of net assets to Devon	(23.2		)
Total net distributions per equity	$	(45.3	)
Discontinued operations:
Revenues - affiliates	$	(10.4	)
Operating costs and expenses - affiliates	5.0
Net affiliate transactions	(5.4		)
Capital expenditures	0.6
Other third-party transactions, net	0.4
Net third-party transactions	1.0
Net cash distributions to Devon and non-controlling interests - discontinued operations	(4.4		)
Non-cash distribution of net assets to Devon	(39.9		)
Total net distributions per equity	$	(44.3	)
Total distributions- continuing and discontinued operations	$	(89.6	)

17

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the six months ended June 30, 2014. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the six months ended June 30, 2014. These amounts are included in general and administrative expenses in the accompanying statements of operations.

(6) Long-Term Debt

As of June 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):

	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9% respectively	$	150.0	$	237.0
Company credit facility (due 2019)	—		—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
The Partnership's senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
The Partnership's senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Partnership's Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, 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 $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

Company Credit Facility

On March 7, 2014, the Company entered into a $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 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 and (iii) 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

18

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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 June 30, 2015 there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility

On February 20, 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership is permitted to, (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership credit facility by an additional amount not to exceed $500 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year. 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 be increased 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.

As of June 30, 2015, there were $2.9 million in outstanding letters of credit and $150.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms of the Partnership credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”) at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

Prior to March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, at any time in whole, or from time to time in part, at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 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

19

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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, in either case, 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.

(7)  Income Taxes

Income taxes included in the condensed consolidated financial statements were as follows for the periods presented.

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
	(in millions)
Predecessor income tax expense	$	—	$	—	$	—	$	19.4
ENLC income tax expense	10.2		18.5		20.9		22.8
Total income tax expense	$	10.2	$	18.5	$	20.9	$	42.2

(8)  Certain Provisions of the Partnership Agreement

(a) Issuance of Common Units

In November 2014, the 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 from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the six months ended June 30, 2015, the Partnership sold an aggregate of 0.2 million common units under the BMO EDA, generating proceeds of approximately $4.1 million (net of less than $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2015, approximately $337.6 million remains available to be issued under the agreement.

20

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(b) Class C Common Units

In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. For further discussion see Note 3- Acquisitions. The Class C Common Units are substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units may be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on the earlier to occur of (i) the date on which the General Partner, in its sole discretion, determines to convert all of the outstanding Class C Common Units into common units and (ii) the first business day following the date of the distribution for the quarter ended March 31, 2016. Distributions on the Class C Common Units for the three months ended March 31, 2015 were paid-in-kind ("PIK") through the issuance of 99,794 Class C Common Units on May 14, 2015. A distribution on the Class C Common Units of $0.385 per unit was declared for the three months ended June 30, 2015, which will result in the issuance of 120,622 additional Class C Common Units on August 13, 2015.

(c) Class D Common Units

In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion see Note 3 - Acquisitions. The Partnership’s Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. The Partnership’s Class D Common Units automatically converted into the Partnership’s common units on a one-for-one basis on May 4, 2015.

(d) Class E Common Units

In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion see Note 5 - Affiliate Transactions. The Partnership’s Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015.

(e)  Distributions

Unless restricted by the terms of the Partnership's credit facility and/or the indentures governing the Partnership’s senior unsecured notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to its general partner or incentive distributions with respect to the Class C Common Units issued in kind.

Under the quarterly incentive distribution provisions, generally the Partnership's General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit.

A summary of the Partnership's distribution activity relating to the common units for the six months ended June 30, 2015 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2014	$	0.375	February 12, 2015
First Quarter of 2015 (1) (2)	$	0.38	May 14, 2015
Second Quarter of 2015 (3)	$	0.385	August 13, 2015

(1) The Partnership declared a partial first quarter 2015 distribution on its Class D Common Units of $0.18 per unit paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.

(2) The Partnership's first quarter distributions on its Class C Common Units of $0.38 per unit were PIK through the issuance of 99,794 Class C Common Units on May 14, 2015.

21

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(3) The Partnership declared a partial second quarter 2015 distribution on its Class E Common Units of $0.15 per unit to be paid on August 13, 2015. Distributions declared for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

(f) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 8(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
Income allocation for incentive distributions	$	11.3		$	5.9		$	20.1		$	7.3
Unit-based compensation attributable to ENLC’s restricted units	(3.9		)	(3.1		)	(10.9		)	(3.7		)
General Partner interest in net income	0.2			0.3			0.3			0.4
General Partner interest in drop down transactions	11.5			40.4			36.1			49.9
General Partner share of net income	$	19.1		$	43.5		$	45.6		$	53.9

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

(9) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested unit-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders.

22

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The following table reflects the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 (in millions, except per unit amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
EnLink Midstream, LLC interest in net income	$	14.5		$	28.8		$	30.8		$	35.6
Distributed earnings allocated to:
Common units (1) (2)	$	41.1		$	36.1		$	81.3		$	50.6
Unvested restricted units (1)	0.3			0.1			0.5			0.3
Total distributed earnings	$	41.4		$	36.2		$	81.8		$	50.9
Undistributed loss allocated to:
Common units	$	(26.7	)	$	(7.4	)	$	(50.7	)	$	(15.2	)
Unvested restricted units	(0.2		)	—			(0.3		)	(0.1		)
Total undistributed loss	$	(26.9	)	$	(7.4	)	$	(51.0	)	$	(15.3	)
Net income allocated to:
Common units	$	14.4		$	28.7		$	30.6		$	35.4
Unvested restricted units	0.1			0.1			0.2			0.2
Total net income	$	14.5		$	28.8		$	30.8		$	35.6
Total basic and diluted net income per unit:
Basic	$	0.09		$	0.18		$	0.19		$	0.22
Diluted	$	0.09		$	0.18		$	0.19		$	0.22

__________________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

(1) Three months ended June 30, 2015 and 2014 represents a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and declared distribution of $0.22 per unit for common units paid on August 14, 2014.

(2) Six months ended June 30, 2015 and 2014 represents a distribution of $0.245 per unit paid in May 2015 and a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and a distribution of $0.18 per unit paid in May 2014 and a distribution of $0.22 per unit for common units paid on August 14, 2014. Additionally, six months ended June 30, 2014 includes declared distribution of $0.05 per unit for Class B Common Units paid on May 15, 2014.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014*
Basic and diluted earnings per unit:
Weighted average common units outstanding	164.2	164.0	164.2	164.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	164.2	164.0	164.2	164.0
Dilutive effect of restricted units issued	0.4	0.3	0.4	0.2
Total weighted average diluted common units outstanding	164.6	164.3	164.6	164.2

_______________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.

23

(10)Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligation:

	June 30, 2015			June 30, 2014
	(in millions)
Beginning asset retirement obligation	$	20.6		$	8.1
Revisions to existing liabilities	(4.0		)	3.4
Liabilities acquired	—			0.5
Accretion	0.3			0.3
Liabilities settled	(3.2		)	—
Ending asset retirement obligation	$	13.7		$	12.3

Asset retirement obligations of $1.1 million and $8.2 million as of June 30, 2015 and December 31, 2014, respectively, are included in Other Current Liabilities.

(11) Investment in Unconsolidated Affiliates

The Partnership's unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in GCF at June 30, 2015 and 2014 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at June 30, 2015 and 2014.

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	Gulf Coast Fractionators		Howard Energy Partners		Total
Three months ended
June 30, 2015
Distributions	$	4.2	$	8.2	$	12.4
Equity in income	$	2.9	$	3.0	$	5.9
June 30, 2014 (1)
Distributions	$	—	$	3.0	$	3.0
Equity in income	$	3.9	$	0.6	$	4.5
Six months ended
June 30, 2015
Distributions	$	6.9	$	12.3	$	19.2
Equity in income	$	6.3	$	3.4	$	9.7
June 30, 2014 (1)
Distributions	$	—	$	5.7	$	5.7
Equity in income	$	8.0	$	0.7	$	8.7

(1) Includes income and distributions for the period from March 7, 2014 through June 30, 2014 for HEP.

24

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	June 30, 2015		December 31, 2014
Gulf Coast Fractionators	$	53.4	$	54.1
Howard Energy Partners	207.8		216.7
Total investments in unconsolidated affiliates	$	261.2	$	270.8

(12) Employee Incentive Plans

(a)Long-Term Incentive Plans

The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements.

The Partnership and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Cost of unit-based compensation allocated to Predecessor general and     administrative expense (1)	$	—	$	—	$	—	$	2.8
Cost of unit-based compensation charged to general and administrative     expense	6.6		5.0		18.5		6.0
Cost of unit-based compensation charged to operating expense	1.1		0.8		3.0		1.0
Total amount charged to income	$	7.7	$	5.8	$	21.5	$	9.8
Interest of non-controlling partners in unit-based compensation	$	3.7	$	2.5	$	9.2	$	3.0
Amount of related income tax benefit recognized in income	$	1.5	$	1.3	$	4.6	$	2.6

(1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity in 2014.

(b)  EnLink Midstream Partners, LP Restricted Incentive Units

The Partnership's 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 six months ended June 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,022,191			$	31.25
Granted	564,524			27.05
Vested*	(261,409		)	28.76
Forfeited	(62,451		)	31.09
Non-vested, end of period	1,262,855			$	29.89
Aggregate intrinsic value, end of period (in millions)	$	27.7

25

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

 * Vested units include 89,679 units withheld for payroll taxes paid on behalf of employees.

The Partnership issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2015, the Partnership issued 128,675 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended    June 30,		Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.4	$	7.2
Fair value of units vested	$	0.5	$	7.5

As of June 30, 2015, there was $24.3 million of unrecognized compensation cost related to non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 2.0 years.

(c)EnLink Midstream Partners, LP Performance Units

In March 2015, the Partnership and ENLC granted performance awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the "GP Plan") and the 2014 Long-Term Incentive Plan (the “LLC Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding the Partnership and the Company (collectively, "EnLink"), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (the “EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership and the designated peer group; (iii) an estimated ranking of the Partnership among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream Partners, LP Performance Units:	2015
Beginning TSR Price	$	27.68
Risk-free interest rate	0.99		%
Volatility factor	33.01		%
Distribution yield	5.66		%

26

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents a summary of the Partnership's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	118,126		35.41
Vested	—		—
Non-vested, end of period	118,126		$	35.41
Aggregate intrinsic value, end of period (in millions)	$	2.6

As of June 30, 2015 there was $3.6 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

(d)EnLink Midstream, LLC’s Restricted Incentive Units

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 units activity for the six months endedJune 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	986,472			$	37.03
Granted	481,042			31.74
Vested*	(258,094		)	35.79
Forfeited	(53,723		)	36.15
Non-vested, end of period	1,155,697			$	35.15
Aggregate intrinsic value, end of period (in millions)	$	35.9

 * Vested units include 82,352 units withheld for payroll taxes paid on behalf of employees.

ENLC issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding. In March 2015, ENLC issued 102,543 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended June 30,		Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.6	$	8.9
Fair value of units vested	$	0.6	$	9.2

As of June 30, 2015, there was $24.1 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted average period of 1.9 years.

27

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(e) EnLink Midstream, LLC's Performance Units

In March 2015, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC and the designated peer group; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream, LLC Performance Units:	2015
Beginning TSR Price	$	34.24
Risk-free interest rate	0.99		%
Volatility factor	33.02		%
Distribution yield	2.98		%

The following table presents a summary of the Company's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	105,080		40.5
Vested	—		—
Non-vested, end of period	105,080		$	40.5
Aggregate intrinsic value, end of period (in millions)	$	3.3

As of June 30, 2015 there was $3.7 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

(13)Derivatives

Interest Rate Swaps

The Partnership entered into interest rate swaps in April and May 2015 in connection with the issuance of the 2025 Notes in May 2015.                

The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015		2015
Settlement gains on derivatives	$	3.6	$	3.6

Commodity Swaps

The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The

28

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the fair value of the Partnership's derivatives are recorded in revenue in the period incurred. In addition, the Partnership's risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where the Partnership receives a percentage of liquids as a fee for processing third-party gas or where the Partnership receives a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of its business and (3) where the Partnership is mitigating the price risk for product held in inventory or storage.

The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014*
Change in fair value of derivatives	$	(2.5	)	$	(1.3	)	$	(6.3	)	$	(2.0	)
Realized gain (loss) on derivatives	3.7			(0.3		)	7.7			(0.9		)
Gain (loss) on derivative activity	$	1.2		$	(1.6	)	$	1.4		$	(2.9	)

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014. 

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):

	June 30, 2015			December 31, 2014
Fair value of derivative assets — current	$	14.0		$	16.7
Fair value of derivative assets — long term	4.9			10.0
Fair value of derivative liabilities — current	(3.5		)	(3.0		)
Fair value of derivative liabilities — long term	(0.8		)	(2.0		)
Net fair value of derivatives	$	14.6		$	21.7

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at June 30, 2015. The remaining term of the contracts extend no later than December 2016.

			June 30, 2015
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(60.5	)	$	18.1
NGL (long contracts)	Swaps	Gallons	35.8		(2.6		)
Natural Gas (short contracts)	Swaps	MMBtu	(3.7	)	2.6
Natural Gas (long contracts)	Swaps	MMBtu	2.7		(3.5		)
Total fair value of derivatives					$	14.6

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

29

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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 June 30, 2015 of $18.9 million would be reduced to $14.6 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 Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):

	Maturity Periods
	Less than one year		One to two years		More than two years		Total fair value
June 30, 2015	$	10.5	$	4.1	$	—	$	14.6

(14)  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 establishes 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 liabilities measured at fair value on a recurring basis are summarized below (in millions):

	June 30, 2015 Level 2		December 31, 2014 Level 2
Commodity Swaps*	$	14.6	$	21.7
Total	$	14.6	$	21.7

__________________________________________________

* 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.

30

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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):

	June 30, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	2,827.2	$	2,757.1	$	2,022.5	$	2,026.1
Obligations under capital leases	$	18.7	$	18.0	$	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 $150.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of June 30, 2015 and December 31, 2014, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2015, the Partnership had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. As of December 31, 2014, the Partnership had total borrowings of $1.8 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes as of June 30, 2015 and 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. 

(15) Commitments and Contingencies

(a) Severance and Change in Control Agreements

Certain members of management of the Partnership are parties to severance and change of control agreements with the General Partner. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such an individual from, among other things, competing with the General Partner or its affiliates during his employment, and disclosing confidential information about, or interfering with a client or customer of, the General Partner or its affiliates during his employment and for a certain period of time following the termination of such person’s employment.

(b) 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.

31

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(c) Litigation Contingencies

The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows. 

At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows.

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. 

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana.  The amount of damages is unspecified. The Partnership's subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area.  On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC ("Texas Brine"), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses.  The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputed the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23^rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

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

32

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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.

(16) Segment Information

Identification of the majority of the Company's operating segments is based principally upon geographic regions served.  The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas ("Texas"), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana ("Louisiana"), natural gas gathering and processing operations located throughout Oklahoma ("Oklahoma") and crude rail, truck, pipeline, and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley ("Crude and Condensate"). The Company's Crude and Condensate segment, which is identified based upon the nature of services provided to customers of the segment, has historically been referred to as the Company's ORV segment. Due to the growth in this segment, including the acquisitions of LPC and VEX, the Company has renamed this segment to more accurately reflect the assets included therein. The Company has restated the prior period to include certain crude and condensate activity in the Crude and Condensate segment. Operating activity for intersegment eliminations is shown in the corporate segment.  The Company’s sales are derived from external domestic customers.

Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and investments in HEP and GCF. The Company evaluates the performance of its operating segments based on operating revenues and segment profits.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
	(In millions)
Three Months Ended June 30, 2015
Product sales	$	81.2		$	401.2		$	0.1		$	473.7		$	—		$	956.2
Product sales-affiliates	35.0			17.0			1.7			14.0			(36.0		)	31.7
Midstream services	36.0			63.2			9.8			26.9			—			135.9
Midstream services-affiliates	115.8			0.3			29.1			4.3			—			149.5
Cost of sales	(118.4		)	(418.2		)	(2.0		)	(465.6		)	36.0			(968.2		)
Operating expenses	(45.5		)	(27.2		)	(9.1		)	(27.3		)	—			(109.1		)
Gain on derivative activity	—			—			—			—			1.2			1.2
Segment profit	$	104.1		$	36.3		$	29.6		$	26.0		$	1.2		$	197.2
Depreciation and amortization	$	(42.8	)	$	(26.9	)	$	(11.8	)	$	(14.5	)	$	(1.7	)	$	(97.7	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	80.9		$	14.7		$	12.3		$	54.4		$	2.5		$	164.8
Three Months Ended June 30, 2014
Product sales	$	68.6		$	514.2		$	—		$	105.1		$	—		$	687.9
Product sales-affiliates	19.3			1.7			—			—			(21.0		)	—
Midstream services	14.6			37.9			—			14.6			—			67.1
Midstream services-affiliates	126.6			—			47.2			—			—			173.8
Cost of sales	(76.1		)	(508.1		)	—			(98.7		)	21.0			(661.9		)
Operating expenses	(38.6		)	(16.5		)	(7.3		)	(11.5		)	—			(73.9		)
Loss on derivative activity	—			—			—			—			(1.6		)	(1.6		)
Segment profit	$	114.4		$	29.2		$	39.9		$	9.5		$	(1.6	)	$	191.4
Depreciation and amortization	$	(32.8	)	$	(19.1	)	$	(11.6	)	$	(10.7	)	$	(0.8	)	$	(75.0	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	75.4		$	121.2		$	(2.2	)	$	33.9		$	3.2		$	231.5

33

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Six Months Ended June 30, 2015
Product sales	$	131.0		$	773.4		$	0.1		$	722.4		$	—		$	1,626.9
Product sales-affiliates	60.9			24.1			5.4			14.0			(56.5		)	47.9
Midstream services	55.6			121.1			20.5			41.1			—			238.3
Midstream services-affiliates	231.3			0.4			60.3			8.5			—			300.5
Cost of sales	(185.6		)	(789.1		)	(7.1		)	(700.3		)	56.5			(1,625.6		)
Operating expenses	(92.6		)	(51.5		)	(16.1		)	(47.4		)	—			(207.6		)
Gain on derivative activity	—			—			—			—			1.4			1.4
Segment profit	$	200.6		$	78.4		$	63.1		$	38.3		$	1.4		$	381.8
Depreciation and amortization	$	(79.2	)	$	(54.4	)	$	(25.3	)	$	(26.9	)	$	(3.2	)	$	(189.0	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	154.4		$	29.9		$	17.5		$	132.0		$	6.7		$	340.5
Six Months Ended June 30, 2014
Product sales	$	114.5		$	649.1		$	11.5		$	126.2		$	—		$	901.3
Product sales-affiliates	311.9			2.3			147.9			—			(25.7		)	436.4
Midstream services	19.5			48.4			—			18.3			—			86.2
Midstream services-affiliates	167.0			—			62.3			—			—			229.3
Cost of sales	(333.4		)	(641.6		)	(133.9		)	(117.6		)	25.7			(1,200.8		)
Operating expenses	(70.3		)	(21.6		)	(14.0		)	(14.7		)	—			(120.6		)
Loss on derivative activity	—			—			—			—			(2.9		)	(2.9		)
Segment profit	$	209.2		$	36.6		$	73.8		$	12.2		$	(2.9	)	$	328.9
Depreciation and amortization	$	(60.1	)	$	(24.3	)	$	(25.8	)	$	(12.4	)	$	(0.9	)	$	(123.5	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	100.5		$	143.3		$	8.0		$	45.0		$	8.7		$	305.5

The table below presents information about segment assets as of June 30, 2015 and December 31, 2014:

	June 30, 2015		December 31, 2014
Segment Identifiable Assets:	(In millions)
Texas	$	4,011.7	$	3,303.0
Louisiana	3,195.5		3,316.5
Oklahoma	885.5		892.8
Crude and Condensate	1,210.6		871.9
Corporate	1,825.2		1,822.5
Total identifiable assets	$	11,128.5	$	10,206.7

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

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Segment profits	$	197.2		$	191.4		$	381.8		$	328.9
General and administrative expenses	(28.1		)	(26.6		)	(70.8		)	(42.5		)
Depreciation and amortization	(97.7		)	(75.0		)	(189.0		)	(123.5		)
Operating income	$	71.4		$	89.8		$	122.0		$	162.9

34

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(17) 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 economic benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

The following schedule summarizes net income from discontinued operations (in millions):

	Six Months Ended   June 30,
	2014
Revenues:
Revenues	$	6.8
Revenues - affiliates	10.5
Total revenues	17.3
Operating costs and expenses:
Operating expenses	15.7
Total operating costs and expenses	15.7
Income before income taxes	1.6
Income tax provision	0.6
Net income	$	1.0

(18) Supplemental Cash Flow Information

The following schedule summarizes the Partnership's non-cash financing activities for the period presented.

	Six Months Ended   June 30,
	2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	180.0
Non-cash issuance of Class C Common Units (1)	$	180.0

(1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.

Also, see Note 5-Affiliate Transactions for non-cash activities related to Predecessor operations with Devon prior to March 7, 2014.

35

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to EnLink Midstream Holdings, LP (“Midstream Holdings”), which is the historical predecessor of EnLink Midstream, LLC and (2) for periods on or after March 7, 2014, the results of operations of EnLink Midstream, LLC, after giving effect to the business combination discussed under “Devon Energy Transaction” below. The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon Energy Corporation (“Devon”) prior to the business combination, including its 38.75% economic interest in Gulf Coast Fractionators ("GCF"). However, in connection with the business combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% economic interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.

You should read this discussion in conjunction with the historical financial statements and accompanying notes included in this report. All references in this section to the "Company", as well as the terms “our,” “we,” “us” and “its” (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream, LLC, together with its consolidated subsidiaries including the Partnership and Midstream Holdings. All references in this section to the "Partnership" (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream Partners, LP, together with its consolidated subsidiaries including EnLink Midstream Operating, LP (the "Operating Partnership"), Midstream Holdings and their consolidated subsidiaries.

Overview

We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in EnLink Midstream Partners, LP, a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. Our interests in EnLink Midstream Partners, LP, consist of the following as of June 30, 2015:

•68,248,199 common units representing an aggregate 26.1% limited partner interest in the Partnership; and

•100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership,

which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business, or to provide for future distributions.

The incentive distribution rights in the Partnership entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. Since the Partnership controls Midstream Holdings through the ownership of its general partner, the financial results of the Partnership consolidate all of Midstream Holdings' financial results. Our condensed consolidated results of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership and Midstream Holdings.

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, brine services and marketing, to producers of natural gas, NGLs, crude oil and condensate. The Partnership's midstream energy asset network includes approximately 9,200 miles of pipelines, sixteen natural gas processing plants, seven fractionators, 3.1 million barrels of NGL cavern storage, 11.0 Bcf of natural gas storage, rail

36

terminals, barge terminals, truck terminals and a fleet of approximately 140 trucks. The Partnership manages and reports its activities primarily according to the nature of activity and geography. The Partnership has five reportable segments: (1) Texas, which includes the Partnership's natural gas gathering, processing and transmission activities in north Texas and the Permian Basin in west Texas; (2) Oklahoma, which includes the Partnership's natural gas gathering, processing and transmission activities in Cana-Woodford and Arkoma-Woodford Shale areas; (3) Louisiana, which includes the Partnership's natural gas pipelines, natural gas processing plants and NGL assets located in Louisiana; (4) Crude and Condensate, which includes the Partnership's Ohio River Valley ("ORV") crude oil, condensate and brine disposal activities in the Utica and Marcellus Shales, its equity interests in E2 Energy Services, LLC, E2 Appalachian Compression, LLC and E2 Ohio Compression, LLC (collectively, "E2"), its crude oil operations in the Permian Basin and its crude oil activities associated with the Victoria Express Pipeline and related truck terminal and storage assets ("VEX") located in the Eagle Ford Shale; and (5) Corporate, which includes the Partnership's equity investments in Howard Energy Partners, in the Eagle Ford Shale, its contractual right to the economic burdens and benefits associated with Devon's ownership interest in GCF in south Texas and our general partnership property and expenses.

The Partnership manages its operations by focusing on gross operating margin because the Partnership's business is generally to gather, process, transport or market natural gas, NGLs, crude oil and condensate using its assets for a fee. The Partnership earns its fees through various contractual arrangements which include stated fixed-fee contract arrangements or arrangements where the Partnership purchases and resells commodities in connection with providing the related service and earns a net margin for its fees. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal, or pipeline. The Partnership defines gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-generally accepted accounting principle ("non-GAAP") financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 95% of the Partnership's gross operating margin (revenues less cost of sales) was derived from fee-based services with no direct commodity exposure for the six months ended June 30, 2015. Accordingly, the Partnership treats all revenue as fee-based midstream services revenue and presents it under the caption “Revenues” on the Condensed Consolidated Statements of Operations.

The Partnership's gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, the volumes of NGLs handled at its fractionation facilities, the volumes of crude oil and condensate handled at its crude terminals, the volumes of crude oil and condensate gathered, transported, purchased and sold and the volume of brine disposed and the volume of condensate stabilized. The Partnership generates revenues from seven primary sources:

•transporting natural gas and NGLs on the pipeline systems it owns;

•processing natural gas at its processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services; and

•providing brine disposal services.

The Partnership typically gathers or transports gas owned by others through its facilities for a fee. The Partnership also buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the market index. The fixed discount difference to a market index represents the fee for using the Partnership's assets. The Partnership attempts to execute substantially all purchases and sales concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the fee it will receive for each natural gas transaction. The Partnership’s gathering and transportation fee related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

37

On occasion the Partnership has entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as its fee. Changes in the basis spread can increase or decrease margins or potentially result in losses. For example, the Partnership is a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. The Partnership buys gas for this contract on several different production-area indices on its North Texas Pipeline and sells the gas into a different market area index. The Partnership realizes a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this 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 prices under this gas delivery contract. As of June 30, 2015, the balance sheet reflects a liability of $71.7 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the cash losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

The Partnership typically transports and fractionates or stores NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The Partnership also buys mixed NGLs from its suppliers at a fixed discount to market indices for the component NGLs with a deduction for its fractionation fee. The Partnership subsequently sells the fractionated NGL products based on the same index-based prices. The operating results of the Partnership's NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With the Partnership's fractionation business, it also has the opportunity for product upgrades for each of the discrete NGL products. The fees the Partnership earns on the product upgrade from this fractionation business is higher during periods with higher liquids prices.

The Partnership generally gathers or transports crude oil and condensate owned by others by rail, truck, pipeline and barge facilities for a fee. The Partnership also buys crude oil and condensate from a producer at a fixed discount to a market index, then transports and resells the crude oil and condensate at the same market index.  The Partnership executes substantially all purchases and sales concurrently, thereby establishing the fee it will receive for each crude oil and condensate transaction. Additionally, the Partnership provides crude oil, condensate and brine services on a volume basis.

The Partnership realizes gross operating margins from its processing services primarily through different contract arrangements: processing margins ("margin"), percentage of liquids (“POL”), percentage of proceeds ("POP") or fixed-fee based. Under margin contract arrangements the Partnership's gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts the Partnership’s gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” 

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas, liquids, crude oil and condensate moved through or by the asset.

Devon Energy Transaction

On March 7, 2014, ENLC consummated the transactions contemplated by the Agreement and Plan of Merger, dated as of October 21, 2013 (the “Merger Agreement”), among EnLink Midstream, Inc. ("EMI"), Devon, Acacia Natural Gas Corp I, Inc., formerly a wholly-owned subsidiary of Devon (“Acacia”), and certain other wholly-owned subsidiaries of Devon pursuant to which EMI and Acacia each became wholly-owned subsidiaries of ENLC (collectively, the “Mergers”). Upon completion of the merger with Acacia, ENLC indirectly owned a 50% limited partner interest in Midstream Holdings. Also on March 7, 2014, the Partnership consummated the transactions contemplated by the Contribution Agreement, dated as of October 21, 2013 (the “Contribution Agreement”), among the Partnership, EnLink Midstream Operating, Devon and certain of Devon’s wholly-owned subsidiaries.

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to the Partnership in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.6% limited partner interest in the Partnership as of June 30, 2015. On May 27, 2015, the Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the "May Transferred Interests") to the Partnership in a drop down transaction (the "May EMH Drop Down" and together with the February EMH

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Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.2% limited partner interest in the Partnership as of June 30, 2015. After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See “Recent Developments.”

As of June 30, 2015, the Partnership units held by Devon represent approximately 28.7% of the outstanding limited partner interests in the Partnership, with approximately 44.8% of the outstanding limited partner interests held by the Partnership’s public unitholders and approximately 26.0% of the outstanding limited partner interests, the approximate 0.5% general partner interest and the incentive distribution rights held indirectly by ENLC.

Recent Developments

Acquisitions

Coronado Midstream. On March 16, 2015, the Partnership acquired all of the voting equity interests in Coronado Midstream Holdings LLC, the parent company of Coronado Midstream LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $602.1 million in cash and equity, subject to certain adjustments. The purchase price consisted of $242.1 million in cash, 6,704,285 common units and 6,704,285 Class C Common Units in the Partnership.  Coronado operates three cryogenic gas processing plants and a gas gathering system in the North Midland Basin including approximately 270 miles of gathering pipelines, 175 million cubic feet per day ("MMcf/d") of processing capacity and 35,000 horsepower of compression. The Coronado system is underpinned by long-term contracts, which include the dedication of production from over 190,000 acres. The Coronado assets are included in the Partnership's Texas segment.

LPC Crude Oil Marketing. On January 31, 2015, the Partnership acquired all of the voting equity interests in LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million. LPC is an integrated crude oil logistics service provider with operations throughout the Permian Basin. LPC's integrated logistics services are supported by 41 tractor trailers, 13 pipeline injection stations and 67 miles of crude oil gathering pipeline.

Drop Downs

VEX Pipeline. On April 1, 2015, the Partnership acquired the VEX Interests from Devon, which are located in the Eagle Ford Shale in south Texas. The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX, subject to certain adjustments set forth in the contribution agreement. The VEX pipeline is a 56-mile multi-grade crude oil pipeline with a current capacity of approximately 50,000 barrels per day ("Bbls/d") and, following completion of currently-underway expansion projects, will have capacity of approximately 90,000 Bbls/d. Other VEX assets at the destination of the pipeline include an eight-bay truck unloading terminal, 200,000 barrels of above-ground storage, of which 50,000 barrels are under construction, and rights to barge loading docks.

Midstream Holdings Drop Down. On February 17, 2015, Acacia contributed the February Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

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Organic Growth

Ohio River Valley Condensate Pipeline and Condensate Stabilization Facilities. In August 2014, the Partnership announced plans to construct a new 45-mile, eight-inch condensate pipeline and six natural gas compression and condensate stabilization facilities that will service major producer customers in the Utica Shale, including Eclipse Resources.  The new-build stabilized condensate pipeline would connect to the Partnership's existing 200-mile pipeline in the ORV, providing producer customers in the region access to premium market outlets through its barge facility on the Ohio River and rail terminal in Ohio.  The Partnership continues to evaluate the optimal timing for construction of the proposed pipeline.  Ultimately, the planned pipeline is expected to have an initial capacity of approximately 50,000 Bbls/d with potential to expand.

Through an agreement with Eclipse Resources (the “Eclipse Agreement”), the Partnership also expects to own and operate four additional natural gas compression and condensate stabilization facilities in Harrison, Monroe and Guernsey counties in Ohio.  The Eclipse Agreement was amended in June 2015 to reduce the total number of facilities from six to four without materially reducing the facilities’ combined compression or stabilization capacities. The Partnership took ownership of and began operating the first two of these facilities in the fourth quarter of 2014.  The third compression and condensate stabilization facility began operations in April 2015.

Riptide Plant. The Partnership acquired the Riptide plant located in the Permian Basin as part of the Coronado acquisition. The plant, which is under construction, will provide 100 MMcf/d of processing capacity and be tied to approximately 40 miles of new pipeline that is also under construction. The Partnership is also expanding four existing compressor stations. The plant is expected to be completed in the first half of 2016.

Partnership Credit Facility

In 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility (the "Partnership credit facility"). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion, and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020.

Issuance of Partnership Common Units

In November 2014, the Partnership entered into an equity distribution agreement (the "BMO EDA") with BMO Capital Markets Corp. and certain other sales agents to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any sales agent as principal for the sales agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA.

For the six months ended June 30, 2015, the Partnership sold an aggregate of $0.2 million common units under the BMO EDA, generating proceeds of approximately $4.1 million (net of approximately $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2015, approximately $337.6 million remains available to be issued under the agreement.

Non-GAAP Financial Measures

Cash Available for Distribution

We define cash available for distribution as distributions due to us from the Partnership and our interest in Midstream Holdings' adjusted EBITDA (as defined herein), less maintenance capital, our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and current taxes attributable to our earnings. During 2014, we utilized federal net operating loss carryforwards to offset our taxable income generated during 2014. We have $48.2 million of federal net operating loss carryforwards remaining as of December 31, 2014. We anticipate that taxable income during 2015 will be sufficient to utilize our remaining net operating loss carryforwards and that we will begin paying federal income taxes on our taxable income. Cash available for distribution is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Cash available for distribution is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment.

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Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

The GAAP measure most directly comparable to cash available for distribution is net income. Cash available for distribution should not be considered as an alternative to GAAP net income. Cash available for distribution is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Because cash available for distribution excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following is a calculation of the Company's cash available for distribution (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(unaudited)
Distribution declared by ENLK associated with (1):
General partner interest	$	0.6		$	0.6		$	1.2		$	1.0
Incentive distribution rights	11.3			5.9			20.1			9.3
ENLK common units owned	24.3			6.0			36.6			11.9
Total share of ENLK distributions declared	$	36.2		$	12.5		$	57.9		$	22.2
Transferred interest EBITDA (2)	15.6			58.4			53.7			73.4
Total cash available	$	51.8		$	70.9		$	111.6		$	95.6
Uses of cash:
General and administrative expenses	(1.0		)	(0.8		)	(1.8		)	(1.8		)
Current income taxes (3)	2.9			(0.4		)	(1.2		)	(0.5		)
Interest expense	(0.1		)	(0.8		)	(0.4		)	(1.1		)
Maintenance capital expenditures (4)	(1.6		)	(1.8		)	(4.0		)	(3.1		)
Total cash used	$	0.2		$	(3.8	)	$	(7.4	)	$	(6.5	)
ENLC cash available for distribution	$	52.0		$	67.1		$	104.2		$	89.1

_________________________________________________

(1) Represents distributions paid to ENLC on May 14, 2015 and distributions declared by ENLK and to be paid to ENLC on August 13, 2015.

(2) Represents ENLC's interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.

(3) Represents ENLC’s stand-alone current tax expense.

(4) Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA per (2) above.

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The following table provides a reconciliation of ENLC net income to ENLC cash available for distribution (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(unaudited)
Net income of ENLC	$	44.6		$	62.4		$	69.6		$	109.9
Less: Net income attributable to ENLK	(55.5		)	(81.8		)	(91.1		)	(135.4		)
Net income of ENLC excluding ENLK	$	(10.9	)	$	(19.4	)	$	(21.5	)	$	(25.5	)
ENLC's share of distributions from ENLK (1)	36.2			12.5			57.9			22.2
ENLC deferred income tax expense (2)	12.4			17.3			17.8			21.5
Depreciation attributable to E2	—			—			—			—
Maintenance capital expenditures (3)	(1.6		)	(1.8		)	(4.0		)	(3.1		)
Transferred interest EBITDA (4)	15.6			58.4			53.7			73.4
Other items (5)	0.3			0.1			0.3			0.6
ENLC cash available for distribution	$	52.0		$	67.1		$	104.2		$	89.1

_________________________________________________

(1) Represents distributions paid to ENLC on May 14, 2015 and distributions declared by ENLK and to be paid to ENLC on August 13, 2015.

(2) Represents ENLC's stand-alone deferred taxes.

(3) Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs, which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA.

(4) Represents ENLC's interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.

(5) Represents E2's adjusted EBITDA and other non-cash items not included in cash available for distributions.

Gross Operating Margin

We define gross operating margin, generally, as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations”.  We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because our business is generally to purchase and resell natural gas, NGLs, condensate and crude oil for a margin or to gather, process, transport or market natural gas, NGLs, condensate and crude oil for a fee. Operating expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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The following table provides a reconciliation of gross operating margin to operating income:

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in millions)
Total gross operating margin	$	306.3		$	265.3		$	589.4		$	449.5
Add (deduct):
Operating expenses	(109.1		)	(73.9		)	(207.6		)	(120.6		)
General and administrative expenses	(28.1		)	(26.6		)	(70.8		)	(42.5		)
Depreciation and amortization	(97.7		)	(75.0		)	(189.0		)	(123.5		)
Operating income	$	71.4		$	89.8		$	122.0		$	162.9

Results of Operations

The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin which we define as operating revenue less cost of sales as reflected in the table below.

Items Affecting Comparability of Our Financial Results

Our historical financial results discussed below may not be comparable to our future financial results, and our financial results for the six months ended June 30, 2015 may not be comparable to our financial results for the six months ended June 30, 2014 for the following reasons:

• In connection with the business combination, Midstream Holdings entered into new agreements with Devon that were entered into January 1, 2014 pursuant to which Midstream Holdings provides services to Devon under fixed-fee arrangements in which Midstream Holdings does not take title to the natural gas gathered or processed or the NGLs it fractionates. Prior to the effectiveness of these agreements, the Predecessor provided services to Devon under a percent-of-proceeds arrangement in which it took title to the natural gas it gathered and processed and the NGLs it fractionated.

• Prior to March 7, 2014, our financial results only included the assets, liabilities and operations of our Predecessor. Beginning on March 7, 2014, our financial results also consolidate the assets, liabilities and operations of the legacy business of the Partnership after giving effect to the business combination.

• Subsequent to March 7, 2014 (and prior to the EMH Drop Downs), we owned a 50% direct ownership interest in Midstream Holdings and indirectly owned an additional interest of approximately 3% of Midstream Holdings (through our ownership in the Partnership which owned the remaining 50% interest in Midstream Holdings) rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. After the February EMH Drop Down on February 17, 2015, we owned a 25% direct ownership interest in Midstream Holdings, and after the May EMH Drop Down on May 27, 2015, we do not own any direct interest in Midstream Holdings. Our financial statements after March 7, 2014 and prior to the EMH Drop Downs consolidate all of Midstream Holdings’ financial results with ours in accordance with GAAP and the Partnership’s interest not owned by us in Midstream Holdings is reflected as a non-controlling interest.

• Our financial statements for the six months ended June 30, 2015 and 2014 report financial results according to operating segments based principally upon geographic regions served. The Predecessor had no operations for certain of those reporting segments.

• All historical affiliated transactions prior to March 7, 2014 related to our continuing operations were net settled within our combined financial statements because these transactions related to Devon and were funded by Devon’s working capital. Beginning on March 7, 2014, all our transactions settle in cash and therefore impact our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

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	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in millions, except volumes)
Texas Segment
Revenues	$	268.0		$	229.1		$	478.8		$	612.9
Cost of sales	(118.4		)	(76.1		)	(185.6		)	(333.4		)
Total gross operating margin	$	149.6		$	153.0		$	293.2		$	279.5
Louisiana Segment
Revenues	$	481.7		$	553.8		$	919.0		$	699.8
Cost of sales	(418.2		)	(508.1		)	(789.1		)	(641.6		)
Total gross operating margin	$	63.5		$	45.7		$	129.9		$	58.2
Oklahoma Segment
Revenues	$	40.7		$	47.2		$	86.3		$	221.7
Cost of sales	(2.0		)	—			(7.1		)	(133.9		)
Total gross operating margin	$	38.7		$	47.2		$	79.2		$	87.8
Crude and Condensate Segment
Revenues	$	518.9		$	119.7		$	786.0		$	144.5
Cost of sales	(465.6		)	(98.7		)	(700.3		)	(117.6		)
Total gross operating margin	$	53.3		$	21.0		$	85.7		$	26.9
Corporate
Revenues	$	(34.8	)	$	(22.6	)	$	(55.1	)	$	(28.6	)
Cost of sales	36.0			21.0			56.5			25.7
Total gross operating margin	$	1.2		$	(1.6	)	$	1.4		$	(2.9	)
Total
Revenues	$	1,274.5		$	927.2		$	2,215.0		$	1,650.3
Cost of sales	(968.2		)	(661.9		)	(1,625.6		)	(1,200.8		)
Total gross operating margin	$	306.3		$	265.3		$	589.4		$	449.5
Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)	2,727,800			2,994,400			2,739,300			2,977,200
Processing (MMBtu/d)	1,262,000			1,156,700			1,199,500			1,146,600
Louisiana (2)
Gathering and Transportation (MMBtu/d)	1,383,300			429,600			1,369,400			426,900
Processing (MMBtu/d)	520,400			591,900			477,600			602,800
NGL Fractionation (Gals/d)	5,862,800			3,360,400			5,748,200			3,355,100
Oklahoma (3)
Gathering and Transportation (MMBtu/d)	413,000			512,500			422,400			461,900
Processing (MMBtu/d)	268,200			458,400			312,100			441,600
Crude and Condensate (2)
Crude Oil Handling (Bbls/d)	141,000			16,300			122,400			16,000
Brine Disposal (Bbls/d)	3,700			5,200			3,700			5,300

__________________________________________________

(1) Volumes for the six month period ended June 30, 2014 includes volumes per day based on a 181-day period for Midstream Holdings' operations plus incremental volumes based on the 116-day period from March 7 to June 30, 2014 for the Partnership’s legacy operations in Texas.

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(2) Volumes include volumes per day based on 91 days for the three months ended June 30, 2014 and based on the 116-day period from March 7 to June 30, 2014 for the six months ended June 30, 2014 for the Partnership’s legacy operations. Midstream Holdings does not have any operations in the Louisiana or Crude and Condensate segments. The VEX pipeline did not commence operation until July 2014.

(3) Volumes include volumes per day based on 91- and 181-day periods for the three and six months ended June 30, 2014, respectively, for Midstream Holdings' operations. The Partnership did not have any legacy operations in Oklahoma.

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Gross Operating Margin. Gross operating margin was $306.3 million for the three months ended June 30, 2015 as compared to $265.3 million for the three months ended June 30, 2014, an increase of $41.0 million, or 15.5%. The overall increase in gross operating margin was primarily due to the acquisition of the LPC assets in January 2015, the acquisition of Coronado assets in March 2015, the start-up of commercial operations of organic projects and an increase in fractionation and marketing activities driven by system expansions. This increase was partially offset by a decline in throughput volumes related to the Partnership's gas processing and transmission activities. The following provides additional details regarding this change in gross operating margin:

• Texas. The Texas segment had a decrease in gross operating margin of $3.4 million for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. The decrease was attributable to a decline in throughput volumes on the Partnership's Texas processing, gathering, and transmission assets of $15.6 million. These decreases were partially offset by an increase of $12.2 million in gross operating margin primarily due to the Coronado acquisition and organic growth of the Bearkat assets located in the Permian Basin.

• Oklahoma. The Oklahoma segment had a decrease in gross operating margin of $8.5 million for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. Of this decrease, $5.5 million is attributable to a decline in volumes. In addition, the Partnership's Cana Plant was down during April and May 2015 for plant repairs, resulting in a decrease in gross operation margin of approximately $3.0 million.

• Louisiana. The Louisiana segment had an increase in gross operating margin of $17.8 million for the three months ended June 30, 2015 as compared to the three months ended June 30, 2014. This increase was primarily driven by the completion of the Cajun-Sibon expansion in September 2014, which increased gross operating margin by $16.1 million. In addition, the Louisiana natural gas processing, gathering and transmission assets contributed an increase of $1.7 million primarily due to the margin contributed by the Gulf Coast natural gas pipeline assets acquired from Chevron in November 2014, which was partially offset by declines in the Partnership's other Louisiana gas assets.

• Crude & Condensate. The Crude and Condensate segment had an increase in gross operating margin of $32.3 million for the three months ended June 30, 2015 as compared to the three months ended June 30, 2014. This increase is attributable to the acquisition of the LPC assets in January 2015 of $14.9 million and the VEX pipeline which commenced operations in July 2014, and contributed $4.2 million. In addition, gross operating margin increased $4.8 million from the Partnership's E2 assets due the commercial start-up of three compression and condensate stabilization stations during the fourth quarter of 2014 and first quarter of 2015. The remaining increase is primarily attributable to the receipt of a one-time termination payment of $10.3 million in connection with the termination of a customer contract in June 2015.

Operating Expenses. Operating expenses were $109.1 million for the three months ended June 30, 2015 as compared to $73.9 million for the three months ended June 30, 2014, an increase of $35.2 million, or 47.6%.

	Three Months Ended June 30,				Change
	2015		2014		$		%
	(in millions)
Texas Segment	$	45.5	$	38.6	$	6.9	17.9	%
Louisiana Segment	27.2		16.5		10.7		64.8	%
Oklahoma Segment	9.1		7.3		1.8		24.7	%
Crude and Condensate Segment	27.3		11.5		15.8		137.4	%
Total	$	109.1	$	73.9	$	35.2	47.6	%

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• Texas Segment. Operating expenses in the Partnership's Texas segment increased $6.9 million for the three months ended June 30, 2015 as compared to the same three-month period in 2014. Of this increase, $7.1 million is attributable to the acquisition of the Coronado assets in March 2015 and the Partnership's Bearkat natural gas processing plant and rich gas gathering system which commenced operations in September 2014.

• Louisiana Segment. Operating expenses in the Partnership's Louisiana segment increased $10.7 million for the three months ended June 30, 2015 as compared to the same three-month period in 2014. Of this increase, $4.6 million is attributable to the acquisition of the Gulf Coast natural gas pipeline assets in November 2014 and $4.4 million is attributable to the Partnership's Cajun-Sibon expansion which went into service in September 2014.

• Oklahoma Segment. Operating expenses in the Partnership's Oklahoma segment increased $1.8 million for the three months ended June 30, 2015 as compared to the same three-month period in 2014. This increase is primarily attributable to repairs at the Partnership's Cana Plant.

• Crude and Condensate Segment. Operating expenses in the Partnership's Crude and Condensate segment increased $15.8 million for the three months ended June 30, 2015 as compared to the same three-month period in 2014. Of this increase, $9.5 million is attributable to the LPC acquisition in January 2015, $3.5 million is attributable to E2 compression and stabilization facilities which went into service during the fourth quarter of 2014 and second quarter of 2015, and $0.8 million is attributable to the Partnership's VEX assets which commenced operation in July of 2014.

General and Administrative Expenses. General and administrative expenses were $28.1 million for the three months ended June 30, 2015 as compared to $26.6 million for the three months ended June 30, 2014, an increase of $1.5 million, or 5.6%. The primary contributors to the total increase are as follows:

•our unit-based compensation expense increased $1.6 million;

•our fees and services expense increased $0.7 million due to the Coronado, LPC and VEX acquisitions; and

•our transition service costs with Devon decreased $1.0 million.

Depreciation and Amortization. Depreciation and amortization expenses were $97.7 million for the three months ended June 30, 2015 as compared to $75.0 million for the three months ended June 30, 2014, an increase of $22.7 million, or 30.3%. Of this increase in depreciation and amortization expenses, $7.5 million is attributable to the acquisition of the Coronado assets in March 2015, $3.0 million is attributable to the LPC acquisition in January 2015 and $3.0 million is attributable to the acquisition of the Gulf Coast natural gas pipeline assets in November 2014. The remaining increase in depreciation and amortization expense of $9.7 million primarily relates to new assets placed in service, of which $3.5 million is attributable to the Partnership's Bearkat assets, $2.7 million is attributable to the additional E2 assets and $4.8 million is attributable to the Cajun Sibon expansion.

Interest Expense. Interest expense was $22.6 million for the three months ended June 30, 2015 as compared to $14.1 million for the three months ended June 30, 2014, an increase of $8.5 million, or 60.3%. Of the increase in interest expense, $12.7 million is attributable to an increase in average debt in 2015 compared to 2014 and $2.7 million is attributable to a decrease in capitalized interest. This increase was partially offset by a $2.6 million decrease due to a decline in average interest rates, a gain on the settlement of interest rate swaps of $3.6 million and an increase in non-cash interest income of $0.7 million attributable to the valuation of the Partnership's mandatorily redeemable non-controlling interest. Net interest expense consists of the following (in millions):

	Three Months Ended    June 30,
	2015			2014
Senior notes	$	25.6		$	16.4
Partnership credit facility	2.2			1.6
Credit facility	0.2			—
Capitalized interest	(1.6		)	(4.3		)
Amortization of debt issue cost, discount and premium	0.1			(0.4		)
Cash settlements on interest rate swaps	(3.6		)	—
Mandatory redeemable non-controlling interest	(0.7		)	—
Other	0.4			0.8
Total	$	22.6		$	14.1

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Income Tax Expense. Income tax expense was $10.2 million for the three months ended June 30, 2015 as compared to income tax expense of $18.5 million for the three months ended June 30, 2014, a decrease of $8.3 million. The decrease in income tax expense is attributable to a decrease in taxable income between periods.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Gross Operating Margin. Gross operating margin was $589.4 million for the six months ended June 30, 2015 as compared to $449.5 million for the six months ended June 30, 2014, an increase of $139.9 million, or 31.1%. Of this increase in gross operating margin, $85.9 million is attributable to the legacy Partnership assets associated with the business combination effective on March 7, 2014, $51.5 million is attributable to the LPC, Coronado and Gulf Coast asset acquisitions, $4.2 million is attributable to the VEX pipeline, which commenced operations in July 2014, and $4.8 million is attributable to our E2 assets due to the commercial start-up of three compression and condensate stabilization stations during the fourth quarter of 2014 and first quarter of 2015. In addition, $10.3 million of the increase is attributable to the termination of a customer contract in June 2015 in which the Partnership received a one-time termination payment of $10.3 million. This increase is partially offset by a $21.1 million decrease in gross operating margin related to a decline in volumes on the Partnership's Texas and Oklahoma assets. Also, the Partnership had a $14.3 million decrease in gross operating margin related to Midstream Holdings, which is the result of the new fixed-fee arrangements with Devon entered into in connection with the business combination.

Operating Expenses. Operating expenses were $207.6 million for the six months ended June 30, 2015 as compared to $120.6 million for the six months ended June 30, 2014, an increase of $87.0 million, or 72.1%. Of this increase in operating expenses, $43.2 million is attributable legacy Partnership assets, $29.7 million is attributable to direct operating costs of the LPC, VEX, Coronado and Gulf Coast asset acquisitions and $5.2 million is attributable to an increase in Midstream Holdings' operating costs.

General and Administrative Expenses. General and administrative expenses were $70.8 million for the six months ended June 30, 2015 as compared to $42.5 million for the six months ended June 30, 2014, an increase of $28.3 million, or 66.6%. Of this increase in general and administrative expenses, $18.8 million is attributable to the legacy Partnership assets, $6.0 million is attributable to certain bonuses paid in March 2015 in the form of unit awards that immediately vested and $4.1 million is attributable to transaction costs related to LPC, Coronado and Gulf Coast asset acquisitions. The increase in general and administrative expenses was partially offset by a $2.6 million decrease attributable to Midstream Holdings. Prior to March 7, 2014, general and administrative expenses were allocated to Midstream Holdings by Devon.

Depreciation and Amortization. Depreciation and amortization expenses were $189.0 million for the six months ended June 30, 2015 as compared to $123.5 million for the six months ended June 30, 2014, an increase of $65.5 million, or 53.0%. Of this increase in depreciation and amortization expenses, $21.8 million is attributable to the legacy Partnership assets acquired in March 2014, $21.0 million is attributable to the LPC, Coronado and Gulf Coast asset acquisitions and $25.4 million is attributable to new assets placed in service. This increase was partially offset by a decrease of $2.0 million in depreciation and amortization expenses related to Midstream Holdings due to the change in depreciation methodology from the units-of-production method to the straight-line method.

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Interest Expense. Interest expense was $41.7 million for the six months ended June 30, 2015 as compared to $19.5 million for the six months ended June 30, 2014, an increase of $22.2 million, or 113.8%. Of the increase in interest expense, $16.2 million is attributable to the number of days debt was outstanding in 2015 compared to 2014 because Midstream Holdings did not have any borrowings prior to March 7, 2014. Interest expense for the six months ended June 30, 2015 includes interest expense for 181 days as compared to 116 days for the six months ended June 30, 2014 (days from March 7, 2014 through June 30, 2014). Further, average debt outstanding increased in 2015 as compared to 2014, which increased interest expense $13.9 million which was partially offset by $3.4 million due to a decrease in average interest rates. This increase was partially offset by an increase due to a gain on the settlement of interest rate swaps of $3.6 million and an increase in non-cash interest income of $3.3 million attributable to the valuation of the Partnership's mandatorily redeemable non-controlling interest. Net interest expense consists of the following (in millions):

	Six Months Ended   June 30,
	2015			2014
Senior notes	$	45.9		$	21.7
Partnership credit facility	4.5			2.8
Credit facility	0.3			—
Capitalized interest	(2.9		)	(5.4		)
Amortization of debt issue cost, discount and premium	—			(0.6		)
Cash Settlements on interest rate swaps	(3.6		)	—
Mandatory redeemable non-controlling interest	(3.3		)	—
Other	0.8			1.0
Total	$	41.7		$	19.5

Income Tax Expense. Income tax expense was $20.9 million for the six months ended June 30, 2015 as compared to income tax expense of $42.2 million for the six months ended June 30, 2014, a decrease of $21.3 million. The decrease in income tax expense is attributable to a decrease in taxable income between periods.

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Impairment of Goodwill. We conduct our annual goodwill impairment test in the fourth quarter each year. As of the date of our last impairment test, the fair values of our Texas, Louisiana, Oklahoma and Crude and Condensate reporting units exceeded their related carrying values. The fair value of our Texas, Oklahoma and Crude and Condensate reporting units substantially exceeded carrying value. However, the fair value of our Louisiana reporting unit is not substantially in excess of its carrying value. The fair value of our Louisiana reporting unit exceeded its carrying value by approximately 14 percent. As of June 30, 2015, we performed a qualitative analysis of goodwill noting no substantial decline in operations that would indicate an impairment. As of June 30, 2015, we had $786.8 million of goodwill allocated to the Louisiana reporting unit.

Significant decreases to our unit price, decreases in commodity prices or negative deviations from projected Louisiana reporting unit earnings could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

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Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $277.0 million for the six months ended June 30, 2015 compared to $203.2 million for the six months ended June 30, 2014. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

	Six Months Ended   June 30,
	2015			2014
Operating cash flows before working capital	$	301.8		$	274.8
Changes in working capital	$	(24.8	)	$	(71.6	)

The primary reason for the increase in operating cash flows before working capital of $27.0 million from 2014 to 2015 relates to an increase in gross operating margin from the acquired legacy Partnership, Coronado, VEX, LPC, E2 and Gulf Coast assets. Gross operating margin also increased due to start up operations of organic growth projects. The change in working capital for 2015 related to fluctuations in trade receivable and payable balances is due to timing of collection and payments and changes in inventory balances due to normal operating fluctuations. Further, prior to March 7, 2014, all cash receipts for the Predecessor were deposited into Devon’s bank accounts, and all cash disbursements were made from these accounts. Cash transactions handled by Devon were reflected in intercompany advances between Devon and the Predecessor, all of which were settled through an adjustment to equity and reflected in cash flows from financing activities. Subsequent to March 7, 2014, Midstream Holdings handles all of its cash transactions and the changes in working capital are reflected in our cash flows from operating activities.

Cash Flows from Investing Activities. Net cash used in investing activities was $665.0 million for the six months ended June 30, 2015 and $463.4 million for the six months ended June 30, 2014. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):

	Six Months Ended   June 30,
	2015			2014
Growth capital expenditures	$	322.9		$	322.2
Maintenance capital expenditures	26.3			14.5
Acquisition of businesses	324.8			126.0
Proceeds from sale of property	(0.1		)	—
Investment in equity investment company	—			5.7
Distribution from equity investment company in excess of earnings	(8.9		)	(5.0		)
Total	$	665.0		$	463.4

Cash Flows from Financing Activities. Net cash provided by financing activities was $391.6 million and $276.1 million for the six months ended June 30, 2015 and 2014, respectively. All Predecessor financing activities from January 1, 2014 through March 6, 2014 totaling $22.1 million are reflected in distributions to Predecessor on the statement of cash flows. Our primary financing activities excluding the period prior to March 7, 2014 consist of the following (in millions):

	Six Months Ended   June 30,
	2015			2014
Net borrowings (repayments) on Partnership's credit facility	$	(87.1	)	$	(209.7	)
Net borrowings on Company's credit facility	—			19.8
Senior unsecured notes borrowings	893.3			1,190.0
Redemption of 2018 Notes	—			(767.6		)
Net borrowings on E2 credit facility	—			9.5
Net repayments under capital lease obligations	(1.6		)	1.2
Debt financing costs	(9.5		)	(7.4		)
Proceeds from issuance of Partnership common units	4.1			20.0

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Distributions to unitholders and Devon also represent a primary use of cash in financing activities. Total cash distributions made during the six months ended June 30, 2015 and 2014 were as follows (in millions):

	Six Months Ended   June 30,
	2015		2014
Distributions to members	$	79.3	$	14.7
Distribution to non-controlling partners	175.7		45.8
Distributions to Devon for net assets acquired	171.0		—

The Partnership received contributions from Devon of $28.8 million for the six months ended June 30, 2015 of which $2.2 million related to the reimbursement of employee costs and $26.6 million relates to funding of capital expenditures for the VEX assets.

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our credit facility. We borrow money under our credit facility to fund checks as they are presented. Change in drafts payable for the six months ended June 30, 2015 and 2014 were as follows (in millions):

	Six Months Ended   June 30,
	2015			2014
Increase (decrease) in drafts payable	$	(12.4	)	$	8.6

Uncertainties. The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC ("Texas Brine"), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses.  The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputes the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23^rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

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.

Capital Requirements. The Partnership considers a number of factors in determining whether its capital expenditures are growth capital expenditures or maintenance capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that the Partnership expects will increase its asset base, operating income or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, gathering or processing assets, in each case to the extent such capital expenditures are expected to expand our asset base, operating capacity or its operating income.

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Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

During the six months ended June 30, 2015, growth capital expenditures were $322.9 million, which were funded by internally generated cash flow and borrowings under the Partnership's credit facility. The Partnership's remaining current growth capital spending projection for 2015 is approximately $250.0 million to $300.0 million, mainly related to its Ripdtide plant and Coronado growth as well as the Cana expansion. The Partnership expects to fund the growth capital expenditures from the proceeds of borrowing under its credit facility and from other debt and equity sources.

The Partnership expects to fund its 2015 maintenance capital expenditures of approximately $15.9 million from operating cash flows. In 2015, it is possible that not all of the planned projects will be commenced or completed. The Partnership's ability to pay distributions to its unitholders and our ability to pay distributions to our unitholders, and the Partnership's ability to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Off-Balance Sheet Arrangements. No off-balance sheet arrangements existed as of June 30, 2015.

Total Contractual Cash Obligations. A summary of contractual cash obligations as of June 30, 2015 is as follows (in millions):

	Payments Due by Period
	Total		Remainder  2015		2016		2017		2018		2019		Thereafter
Long-term debt obligations	$	2,662.5	$	—	$	—	$	—	$	—	$	400.0	$	2,262.5
Partnership credit facility	150.0		—		—		—		—		—		150.0
Other debt	0.3		0.1		0.1		0.1		—		—		—
Interest payable on fixed long-term debt obligations	1,905.0		61.7		120.0		120.0		120.0		114.6		1,368.7
Capital lease obligations	20.9		2.6		4.9		6.9		2.9		1.6		2.0
Operating lease obligations	114.7		4.4		10.5		7.2		12.1		9.3		71.2
Purchase obligations	185.5		185.5		—		—		—		—		—
Delivery contract obligation	71.7		9.0		17.9		17.9		17.9		9.0		—
Pipeline capacity and deficiency agreements (1)	25.0		2.8		8.2		5.8		6.0		2.2		—
Inactive easement commitment (2)	8.0		1.0		1.0		1.0		1.0		1.0		3.0
Uncertain tax position obligations	1.5		1.5		—		—		—		—		—
Total contractual obligations	$	5,145.1	$	268.6	$	162.6	$	158.9	$	159.9	$	537.7	$	3,857.4

__________________________________________________

(1) Consists of pipeline capacity payments for firm transportation and deficiency agreements.

(2) Amounts related to inactive easements paid as utilized by the Partnership with balance due at end of 10 years if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

The interest payable under the Partnership’s credit facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time. However, given the same borrowing amount and rates in effect at June 30, 2015, the cash obligation for interest expense on the Partnership’s credit facility would be approximately $3.5 million per year or approximately $1.7 million for the remainder of 2015.

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Indebtedness

As of June 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):

	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9% respectively	$	150.0	$	237.0
Company credit facility (due 2019)	—		—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
The Partnership's senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
The Partnership's senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Partnership's Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, 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 $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

Company Credit Facility. On March 7, 2014, the Company entered into a $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 and (iii) any additional equity interests subsequently pledged as collateral under the credit facility.

As of June 30, 2015 there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility.  As of June 30, 2015, there were $2.9 million in outstanding letters of credit and $150.0 million of outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion. The credit facility will mature on March 6, 2020, unless we request, and the requisite lenders agree, to extend it pursuant to its terms.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”) at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

See Note 6 to the condensed consolidated financial statements titled “Long-Term Debt” for further details.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the

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Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the 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 six months ended June 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of federal securities laws. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part II, “Item 1A. Risk Factors” of this report may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission ("CFTC") to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement mandates in new legislation to cause significant portions of derivatives markets to clear through clearinghouses. The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any future new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations.

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. We currently process gas under three main types of contractual arrangements as summarized

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below. Approximately 89% of our processing margins are from fixed fee based contracts for the six months ended June 30, 2015. During March 2015 the Partnership acquired processing plants from Coronado which generate gross operating margins based on percent of proceeds contracts.

1. Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or "PTR". The Partnership's margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2.Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, the Partnership's margins from these contracts are greater during periods of high liquids prices. The Partnership's margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3. Percent of proceeds contracts: Under these contracts, the Partnership receives a fee as a portion of the proceeds of the sale of natural gas and liquids. Therefore, the Partnership's margins from these contracts are greater during periods of high natural gas and liquids prices. The Partnership's margins from processing cannot become negative under percent of proceeds contracts, but do decline during periods of low natural gas and NGL prices.

4.Fee based contracts: Under these contracts we have no direct commodity price exposure and are paid a fixed fee per unit of volume that is processed.

The Partnership's primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

The Partnership has hedged its exposure to fluctuations in prices for natural gas and NGL volumes produced for its account. The Partnership hedges its exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. Further, the Partnership has tailored its hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of its physical equity volumes. The NGL hedges cover specific NGL products based upon the Partnership's expected equity NGL composition.

The following table sets forth certain information related to derivative instruments outstanding at June 30, 2015 mitigating the risks associated with the gas processing and fractionation components of the Partnership's business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by OPIS. The relevant index price for Natural Gas is Henry Hub Gas Daily is as defined by the pricing dates in the swap contracts.

Period	Underlying	Notional Volume		We Pay	We Receive *	Fair Value Asset/(Liability)
						(in millions)
July 2015 - December 2016	Ethane	974	(MBbls)	$0.2765/gal	Index	$	(2.6	)
July 2015 - December 2016	Propane	1,094	(MBbls)	Index	$0.8983/gal	17.5
July 2015 - June 2016	Normal Butane	132	(MBbls)	Index	$0.7184/gal	0.4
July 2015 - June 2016	Natural Gasoline	93	(MBbls)	Index	$1.3035/gal	0.2
July 2015 - June 2016	Natural Gas	4,107	(MMBtu/d)	$3.27/MMBtu*	Index	(0.9		)
						$	14.6

__________________________________________________

*weighted average

54

Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves the Partnership with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

As of June 30, 2015, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $14.6 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas and NGL prices would result in a change of approximately $2.8 million in the net fair value of these contracts as of June 30, 2015. 

Interest Rate Risk

The Company had no outstanding borrowings on its variable rate credit facility as of June 30, 2015.

The Partnership is exposed to interest rate risk on its variable rate credit facility. At June 30, 2015, the Partnership's credit facility had $150.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change its annual interest expense by approximately $1.5 million for the year. The Partnership is not exposed to changes in interest rates with respect to its senior unsecured notes due in 2019, 2022, 2024, 2025, 2044, or 2045 as these are fixed-rate obligations. The estimated fair value of the Partnership's senior unsecured notes was approximately $2,606.8 million as of June 30, 2015, based on market prices of similar debt at June 30, 2015. Market risk is estimated as the potential decrease in fair value of the Partnership's long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $229.8 million decrease in fair value of the Partnership's senior unsecured notes at June 30, 2015.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of EnLink Midstream Manager, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (June 30, 2015), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations, or cash flows.

55

For a discussion of certain litigation and similar proceedings, please refer to Note 15, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

56

Item 6. Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Number		Description
2.1**	—	Contribution, Conveyance and Assumption Agreement, dated as of May 27, 2015, by and between EnLink Midstream Partners, LP and Devon Gas Services, L.P. (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 27, 2015, filed with the Commission on May 27, 2015).
3.1	—	Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, file No. 333-192419).
3.2	—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-4, file No. 333-192419).
3.3	—	First Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of March 7, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
3.4	—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.5	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.6	—	First Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.14 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.7	—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, file No. 000-50067).
3.9	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014).
3.10	—	Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP dated July 7, 2014 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
3.11	—	Amendment No. 1 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of February 17, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 17, 2015, filed with the Commission on February 17, 2015).
3.12	—	Amendment No. 2 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of March 16, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 16, 2015, filed with the Commission on March 16, 2015).
3.13	—	Amendment No. 3 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of May 27, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 27, 2015, filed with the Commission on May 27, 2015).
3.14	—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.15	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, file No. 333-194465).
10.1	—	Commitment Increase and Extension Agreement, dated as of February 5, 2015, by and among EnLink Midstream Partners, LP, the Lenders party thereto, and Bank of America, N.A., as an L/C Issuer, as Swing Line Lender, and as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 5, 2015, filed with the Commission on February 11, 2015).
10.2†	—	Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).

57

10.3†	—	Form of Performance Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.4†	—	Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.5†	—	Form of Restricted Incentive Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
31.1*	—	Certification of the Principal Executive Officer.
31.2*	—	Certification of the Principal Financial Officer.
32.1*	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101*	—	The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, (ii) Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014, (iii) Consolidated Statements of Changes in Members’ Equity for the six months ended June 30, 2015, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014, and (v) the Notes to Condensed Consolidated Financial Statements.

__________________________________________________

*     Filed herewith.

**  Pursuant to Item 601(b)(2) of Regulation S-K, the Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

† This Exhibit is identified as a management contract or compensatory benefit plan or arrangement.

58

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EnLink Midstream, LLC
By:	EnLink Midstream Manager, LLC,
	its managing member
By:	/s/ MICHAEL J. GARBERDING
	Michael J. Garberding
	Executive Vice President and Chief Financial Officer

August 5, 2015

59

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barry E. Davis, President and Chief Executive Officer of EnLink Midstream Manager, LLC, the managing member of the registrant, certify that:

1. I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ BARRY E. DAVIS
	BARRY E. DAVIS
	President and Chief Executive Officer
	(principal executive officer)
Date: August 5, 2015

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Michael J. Garberding, Executive Vice President and Chief Financial Officer of EnLink Midstream Manager, LLC, the managing member of the registrant, certify that:

1. I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ MICHAEL J. GARBERDING
	MICHAEL J. GARBERDING
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)
Date: August 5, 2015

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of EnLink Midstream, LLC (the “Registrant”) on Form 10-Q for the quarter ended June 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Barry E. Davis, Chief Executive Officer of EnLink Midstream Manager, LLC, and Michael J. Garberding, Chief Financial Officer of EnLink Midstream Manager, LLC, certifies, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chief Executive Officer
August 5, 2015
	/s/ MICHAEL J. GARBERDING
	Michael J. Garberding
	Chief Financial Officer
August 5, 2015

A signed original of this written statement required by Section 906 has been provided to the Registrant and will be retained by the Registrant and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2015

Segment Reporting [Abstract]

Company Reportable Segment

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
	(In millions)
Three Months Ended June 30, 2015
Product sales	$	81.2		$	401.2		$	0.1		$	473.7		$	—		$	956.2
Product sales-affiliates	35.0			17.0			1.7			14.0			(36.0		)	31.7
Midstream services	36.0			63.2			9.8			26.9			—			135.9
Midstream services-affiliates	115.8			0.3			29.1			4.3			—			149.5
Cost of sales	(118.4		)	(418.2		)	(2.0		)	(465.6		)	36.0			(968.2		)
Operating expenses	(45.5		)	(27.2		)	(9.1		)	(27.3		)	—			(109.1		)
Gain on derivative activity	—			—			—			—			1.2			1.2
Segment profit	$	104.1		$	36.3		$	29.6		$	26.0		$	1.2		$	197.2
Depreciation and amortization	$	(42.8	)	$	(26.9	)	$	(11.8	)	$	(14.5	)	$	(1.7	)	$	(97.7	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	80.9		$	14.7		$	12.3		$	54.4		$	2.5		$	164.8
Three Months Ended June 30, 2014
Product sales	$	68.6		$	514.2		$	—		$	105.1		$	—		$	687.9
Product sales-affiliates	19.3			1.7			—			—			(21.0		)	—
Midstream services	14.6			37.9			—			14.6			—			67.1
Midstream services-affiliates	126.6			—			47.2			—			—			173.8
Cost of sales	(76.1		)	(508.1		)	—			(98.7		)	21.0			(661.9		)
Operating expenses	(38.6		)	(16.5		)	(7.3		)	(11.5		)	—			(73.9		)
Loss on derivative activity	—			—			—			—			(1.6		)	(1.6		)
Segment profit	$	114.4		$	29.2		$	39.9		$	9.5		$	(1.6	)	$	191.4
Depreciation and amortization	$	(32.8	)	$	(19.1	)	$	(11.6	)	$	(10.7	)	$	(0.8	)	$	(75.0	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	75.4		$	121.2		$	(2.2	)	$	33.9		$	3.2		$	231.5

Six Months Ended June 30, 2015
Product sales	$	131.0		$	773.4		$	0.1		$	722.4		$	—		$	1,626.9
Product sales-affiliates	60.9			24.1			5.4			14.0			(56.5		)	47.9
Midstream services	55.6			121.1			20.5			41.1			—			238.3
Midstream services-affiliates	231.3			0.4			60.3			8.5			—			300.5
Cost of sales	(185.6		)	(789.1		)	(7.1		)	(700.3		)	56.5			(1,625.6		)
Operating expenses	(92.6		)	(51.5		)	(16.1		)	(47.4		)	—			(207.6		)
Gain on derivative activity	—			—			—			—			1.4			1.4
Segment profit	$	200.6		$	78.4		$	63.1		$	38.3		$	1.4		$	381.8
Depreciation and amortization	$	(79.2	)	$	(54.4	)	$	(25.3	)	$	(26.9	)	$	(3.2	)	$	(189.0	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	154.4		$	29.9		$	17.5		$	132.0		$	6.7		$	340.5
Six Months Ended June 30, 2014
Product sales	$	114.5		$	649.1		$	11.5		$	126.2		$	—		$	901.3
Product sales-affiliates	311.9			2.3			147.9			—			(25.7		)	436.4
Midstream services	19.5			48.4			—			18.3			—			86.2
Midstream services-affiliates	167.0			—			62.3			—			—			229.3
Cost of sales	(333.4		)	(641.6		)	(133.9		)	(117.6		)	25.7			(1,200.8		)
Operating expenses	(70.3		)	(21.6		)	(14.0		)	(14.7		)	—			(120.6		)
Loss on derivative activity	—			—			—			—			(2.9		)	(2.9		)
Segment profit	$	209.2		$	36.6		$	73.8		$	12.2		$	(2.9	)	$	328.9
Depreciation and amortization	$	(60.1	)	$	(24.3	)	$	(25.8	)	$	(12.4	)	$	(0.9	)	$	(123.5	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	100.5		$	143.3		$	8.0		$	45.0		$	8.7		$	305.5

Segment Table Reconciliation to Condensed Consolidated Financial Statement

The table below presents information about segment assets as of June 30, 2015 and December 31, 2014:

	June 30, 2015		December 31, 2014
Segment Identifiable Assets:	(In millions)
Texas	$	4,011.7	$	3,303.0
Louisiana	3,195.5		3,316.5
Oklahoma	885.5		892.8
Crude and Condensate	1,210.6		871.9
Corporate	1,825.2		1,822.5
Total identifiable assets	$	11,128.5	$	10,206.7

Reconciliation of Operating Profit (Loss) from Segments to Consolidated

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

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Segment profits	$	197.2		$	191.4		$	381.8		$	328.9
General and administrative expenses	(28.1		)	(26.6		)	(70.8		)	(42.5		)
Depreciation and amortization	(97.7		)	(75.0		)	(189.0		)	(123.5		)
Operating income	$	71.4		$	89.8		$	122.0		$	162.9

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Long-term Debt (Phantom) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	May. 12, 2015
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	0.50%
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	2.30%	1.90%
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.70%	2.70%
Debt Instrument, Unamortized Discount (Premium), Net	$ (0.4)	$ (0.5)
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.125%	7.125%
Debt Instrument, Unamortized Discount (Premium), Net	$ 20.4	$ 21.9
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.40%	4.40%
Debt Instrument, Unamortized Discount (Premium), Net	$ 3.0	$ 3.2
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.60%	5.60%
Debt Instrument, Unamortized Discount (Premium), Net	$ (0.3)	$ (0.3)
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.05%	5.05%	5.05%
Debt Instrument, Unamortized Discount (Premium), Net	$ (7.0)	$ (1.7)
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%	0.00%	4.15%
Debt Instrument, Unamortized Discount (Premium), Net	$ (1.3)

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Goodwill and Intangible Assets (Details) - USD ($) $ in Millions			6 Months Ended
	Mar. 16, 2015	Jan. 31, 2015	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Goodwill [Line Items]
Goodwill			$ 3,731.2	$ 3,684.7	$ 3,693.5
Texas Operating Segment
Goodwill [Line Items]
Goodwill			1,185.0	1,168.2	1,168.1
Louisiana Operating Segment
Goodwill [Line Items]
Goodwill			786.8	786.8	786.7
Oklahoma Operating Segment
Goodwill [Line Items]
Goodwill			190.3	190.3	190.3
Crude And Condensate Segment [Member]
Goodwill [Line Items]
Goodwill			142.1	112.5	$ 118.0
Corporation [Member]
Goodwill [Line Items]
Goodwill			1,427.0	$ 1,426.9
LPC [Member]
Goodwill [Line Items]
Goodwill		$ 29.6
Increase in the Partnership's goodwill			29.6
Finite-Lived Intangible Asset, Useful Life		10 years
Coronado [Member]
Goodwill [Line Items]
Goodwill	$ 16.9
Increase in the Partnership's goodwill			$ 16.9
Finite-Lived Intangible Asset, Useful Life	10 years
Minimum [Member]
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life			5 years
Maximum [Member]
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life			20 years

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Derivatives (Details Textuals) $ in Millions	Jun. 30, 2015 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum counterparty loss	$ 18.9
Maximum counterparty loss with netting feature	$ 14.6

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Income Tax (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$ 10.2	$ 18.5	$ 20.9	$ 42.2
Predecessor [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	0.0	0.0	0.0	19.4
Enlink midstream, LLC [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$ 10.2	$ 18.5	$ 20.9	$ 22.8

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Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues				$ 6.8
Revenues - affiliates				10.5
Total revenues				17.3
Operating expenses				15.7
Total operating costs and expenses				15.7
Income before income taxes				1.6
Income tax provision				0.6
Net income	$ 0.0	$ 0.0	$ 0.0	$ 1.0
Gulf Coast Fractionators [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership Percentage	38.75%		38.75%

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Acquisition Phantom (Details) - USD ($) $ in Millions	Mar. 16, 2015	Jan. 31, 2015
LPC [Member]
Business Acquisition [Line Items]
Cash Acquired from Acquisition		$ 21.1
Business Combination, Consideration Transferred, Other		$ 78.9
Coronado [Member]
Business Acquisition [Line Items]
Cash Acquired from Acquisition	$ 9.6
Business Combination, Consideration Transferred, Other	$ 232.5

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Earnings per Unit and Dilution Computations (Tables)

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The following table reflects the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 (in millions, except per unit amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
EnLink Midstream, LLC interest in net income	$	14.5		$	28.8		$	30.8		$	35.6
Distributed earnings allocated to:
Common units (1) (2)	$	41.1		$	36.1		$	81.3		$	50.6
Unvested restricted units (1)	0.3			0.1			0.5			0.3
Total distributed earnings	$	41.4		$	36.2		$	81.8		$	50.9
Undistributed loss allocated to:
Common units	$	(26.7	)	$	(7.4	)	$	(50.7	)	$	(15.2	)
Unvested restricted units	(0.2		)	—			(0.3		)	(0.1		)
Total undistributed loss	$	(26.9	)	$	(7.4	)	$	(51.0	)	$	(15.3	)
Net income allocated to:
Common units	$	14.4		$	28.7		$	30.6		$	35.4
Unvested restricted units	0.1			0.1			0.2			0.2
Total net income	$	14.5		$	28.8		$	30.8		$	35.6
Total basic and diluted net income per unit:
Basic	$	0.09		$	0.18		$	0.19		$	0.22
Diluted	$	0.09		$	0.18		$	0.19		$	0.22

__________________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

(1) Three months ended June 30, 2015 and 2014 represents a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and declared distribution of $0.22 per unit for common units paid on August 14, 2014.

(2) Six months ended June 30, 2015 and 2014 represents a distribution of $0.245 per unit paid in May 2015 and a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and a distribution of $0.18 per unit paid in May 2014 and a distribution of $0.22 per unit for common units paid on August 14, 2014. Additionally, six months ended June 30, 2014 includes declared distribution of $0.05 per unit for Class B Common Units paid on May 15, 2014.

Schedule of Weighted Average Number of Shares

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014*
Basic and diluted earnings per unit:
Weighted average common units outstanding	164.2	164.0	164.2	164.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	164.2	164.0	164.2	164.0
Dilutive effect of restricted units issued	0.4	0.3	0.4	0.2
Total weighted average diluted common units outstanding	164.6	164.3	164.6	164.2

_______________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

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Supplemental Cash Flow Information (Details) $ in Millions	6 Months Ended
	Jun. 30, 2015 USD ($)
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given	$ 180.0
Common Class C [Member]
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given	$ 180.0

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Fair Value Measurement (Fair Value of Financial Instrument) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 2,827.2	$ 2,022.5
Obligations under capital lease	18.7	20.3
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	2,757.1	2,026.1
Obligations under capital lease	$ 18.0	$ 19.8

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Certain Provision of the Partnership Agreement (Allocated Net Income (loss) to the General Partner) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Incentive Distribution Made to Managing Member or General Partner [Line Items]
General Partner share of net income	$ 19.1	$ 43.5	$ 45.6	$ 53.9
General Partner Interest
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Income allocation for incentive distributions	11.3	5.9	20.1	7.3
Unit-based compensation attributable to ENLC’s restricted units	(3.9)	(3.1)	(10.9)	(3.7)
General Partner interest in net income	0.2	0.3	0.3	0.4
General Partners interest in asset drop	$ 11.5	$ 40.4	$ 36.1	$ 49.9

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Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Product sales	$ 956.2	$ 687.9	$ 1,626.9	$ 901.3
Product sales - affiliates	31.7	0.0	47.9	436.4
Midstream services	135.9	67.1	238.3	86.2
Midstream services - affiliates	149.5	173.8	300.5	229.3
Cost of sales	(968.2)	(661.9)	(1,625.6)	(1,200.8)
Operating expenses	(109.1)	(73.9)	(207.6)	(120.6)
Gain on derivative activity	1.2	(1.6)	1.4	(2.9)
Segment profit	197.2	191.4	381.8	328.9
Depreciation and amortization	(97.7)	(75.0)	(189.0)	(123.5)
Goodwill	3,731.2	3,693.5	3,731.2	3,693.5	$ 3,684.7
Capital expenditures	164.8	231.5	340.5	305.5
Segment identifiable assets	11,128.5		11,128.5		10,206.7
Texas Operating Segment
Segment Reporting Information [Line Items]
Product sales	81.2	68.6	131.0	114.5
Product sales - affiliates	35.0	19.3	60.9	311.9
Midstream services	36.0	14.6	55.6	19.5
Midstream services - affiliates	115.8	126.6	231.3	167.0
Cost of sales	(118.4)	(76.1)	(185.6)	(333.4)
Operating expenses	(45.5)	(38.6)	(92.6)	(70.3)
Gain on derivative activity	0.0	0.0	0.0	0.0
Segment profit	104.1	114.4	200.6	209.2
Depreciation and amortization	(42.8)	(32.8)	(79.2)	(60.1)
Goodwill	1,185.0	1,168.1	1,185.0	1,168.1	1,168.2
Capital expenditures	80.9	75.4	154.4	100.5
Segment identifiable assets	4,011.7		4,011.7		3,303.0
Louisiana Operating Segment
Segment Reporting Information [Line Items]
Product sales	401.2	514.2	773.4	649.1
Product sales - affiliates	17.0	1.7	24.1	2.3
Midstream services	63.2	37.9	121.1	48.4
Midstream services - affiliates	0.3	0.0	0.4	0.0
Cost of sales	(418.2)	(508.1)	(789.1)	(641.6)
Operating expenses	(27.2)	(16.5)	(51.5)	(21.6)
Gain on derivative activity	0.0	0.0	0.0	0.0
Segment profit	36.3	29.2	78.4	36.6
Depreciation and amortization	(26.9)	(19.1)	(54.4)	(24.3)
Goodwill	786.8	786.7	786.8	786.7	786.8
Capital expenditures	14.7	121.2	29.9	143.3
Segment identifiable assets	3,195.5		3,195.5		3,316.5
Oklahoma Operating Segment
Segment Reporting Information [Line Items]
Product sales	0.1	0.0	0.1	11.5
Product sales - affiliates	1.7	0.0	5.4	147.9
Midstream services	9.8	0.0	20.5	0.0
Midstream services - affiliates	29.1	47.2	60.3	62.3
Cost of sales	(2.0)	0.0	(7.1)	(133.9)
Operating expenses	(9.1)	(7.3)	(16.1)	(14.0)
Gain on derivative activity	0.0	0.0	0.0	0.0
Segment profit	29.6	39.9	63.1	73.8
Depreciation and amortization	(11.8)	(11.6)	(25.3)	(25.8)
Goodwill	190.3	190.3	190.3	190.3	190.3
Capital expenditures	12.3	(2.2)	17.5	8.0
Segment identifiable assets	885.5		885.5		892.8
Crude And Condensate Segment [Member]
Segment Reporting Information [Line Items]
Product sales	473.7	105.1	722.4	126.2
Product sales - affiliates	14.0	0.0	14.0	0.0
Midstream services	26.9	14.6	41.1	18.3
Midstream services - affiliates	4.3	0.0	8.5	0.0
Cost of sales	(465.6)	(98.7)	(700.3)	(117.6)
Operating expenses	(27.3)	(11.5)	(47.4)	(14.7)
Gain on derivative activity	0.0	0.0	0.0	0.0
Segment profit	26.0	9.5	38.3	12.2
Depreciation and amortization	(14.5)	(10.7)	(26.9)	(12.4)
Goodwill	142.1	118.0	142.1	118.0	112.5
Capital expenditures	54.4	33.9	132.0	45.0
Segment identifiable assets	1,210.6		1,210.6		871.9
Corporate Segment
Segment Reporting Information [Line Items]
Product sales	0.0	0.0	0.0	0.0
Product sales - affiliates	(36.0)	(21.0)	(56.5)	(25.7)
Midstream services	0.0	0.0	0.0	0.0
Midstream services - affiliates	0.0	0.0	0.0	0.0
Cost of sales	36.0	21.0	56.5	25.7
Operating expenses	0.0	0.0	0.0	0.0
Gain on derivative activity	1.2	(1.6)	1.4	(2.9)
Segment profit	1.2	(1.6)	1.4	(2.9)
Depreciation and amortization	(1.7)	(0.8)	(3.2)	(0.9)
Goodwill	1,427.0	1,430.4	1,427.0	1,430.4
Capital expenditures	2.5	$ 3.2	6.7	$ 8.7
Segment identifiable assets	$ 1,825.2		$ 1,825.2		$ 1,822.5

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Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting [Abstract]
Segment profits	$ 197.2	$ 191.4	$ 381.8	$ 328.9
General and administrative expenses	(28.1)	(26.6)	(70.8)	(42.5)
Depreciation and amortization	(97.7)	(75.0)	(189.0)	(123.5)
Operating income	$ 71.4	$ 89.8	$ 122.0	$ 162.9

XML

Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) $ in Millions	Jun. 30, 2015 USD ($)
Derivative [Line Items]
Derivative instruments at fair value	$ 14.6
Market Approach Valuation Technique | Less than one year
Derivative [Line Items]
Derivative instruments at fair value	10.5
Market Approach Valuation Technique | One to two years
Derivative [Line Items]
Derivative instruments at fair value	4.1
Market Approach Valuation Technique | More than two years
Derivative [Line Items]
Derivative instruments at fair value	$ 0.0

XML

Supplemental Cash Flow Information (Notes)

6 Months Ended

Jun. 30, 2015

Supplemental Cash Flow Elements [Abstract]

Cash Flow, Supplemental Disclosures

(18) Supplemental Cash Flow Information

The following schedule summarizes the Partnership's non-cash financing activities for the period presented.

	Six Months Ended   June 30,
	2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	180.0
Non-cash issuance of Class C Common Units (1)	$	180.0

(1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.

Also, see Note 5-Affiliate Transactions for non-cash activities related to Predecessor operations with Devon prior to March 7, 2014.

XML

Goodwill and Intangible Assets (Amortization Expense Table) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Finite-Lived Intangibles Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2015	$ 33.2
2016	66.4
2017	66.4
2018	66.3
2019	65.5
Thereafter	542.7
Total	$ 840.5	$ 533.0

XML

Organization and Summary of Significant Agreements (Details Textuals) - shares				6 Months Ended	12 Months Ended
	May. 27, 2015	Feb. 17, 2015	Oct. 22, 2014	Jun. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Partnership name				EnLink Midstream Partners GP, LLC
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			1,000,000.0		115,495,669
EMI [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				5.30%
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				5.30%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				0.50%
Devon Energy Corporation
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest					70.00%
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				50.00%
ENLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				26.13%
Common units				68,248,199
Enlink midstream, LLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest					50.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
EMH Drop Down [Member] | Affiliated Entity [Member] | Midstream Holdings [Member] | EnLink Midstream LP [Member]
Business Acquisition [Line Items]
Related Party Transaction, Ownership Interest Transferred	100.00%
EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream Holdings, LP [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Related Party Transaction, Ownership Interest Transferred	25.00%	25.00%
Class D Common Unit [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream Holdings, LP [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				9.60%
Related Party Transaction, Amounts of Transaction, Shares		31,618,311
Class E Common Unit [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream Holdings, LP [Member] | EnLink Midstream LP [Member] | Midstream Holdings [Member] | Acacia [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				11.20%
Related Party Transaction, Amounts of Transaction, Shares	36,629,888

XML

Commitments and Contingencies (Details) $ in Millions	1 Months Ended
	Aug. 31, 2014 USD ($)
Gain Contingencies [Line Items]
Gain on Litigation Settlement	$ 6.1

XML

Derivatives (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Interest Rate Derivatives [Table Text Block]

The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015		2015
Settlement gains on derivatives	$	3.6	$	3.6

Commodity Swap

The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014*
Change in fair value of derivatives	$	(2.5	)	$	(1.3	)	$	(6.3	)	$	(2.0	)
Realized gain (loss) on derivatives	3.7			(0.3		)	7.7			(0.9		)
Gain (loss) on derivative activity	$	1.2		$	(1.6	)	$	1.4		$	(2.9	)

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 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):

	June 30, 2015			December 31, 2014
Fair value of derivative assets — current	$	14.0		$	16.7
Fair value of derivative assets — long term	4.9			10.0
Fair value of derivative liabilities — current	(3.5		)	(3.0		)
Fair value of derivative liabilities — long term	(0.8		)	(2.0		)
Net fair value of derivatives	$	14.6		$	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 and related physical offsets at June 30, 2015. The remaining term of the contracts extend no later than December 2016.

			June 30, 2015
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(60.5	)	$	18.1
NGL (long contracts)	Swaps	Gallons	35.8		(2.6		)
Natural Gas (short contracts)	Swaps	MMBtu	(3.7	)	2.6
Natural Gas (long contracts)	Swaps	MMBtu	2.7		(3.5		)
Total fair value of derivatives					$	14.6

Derivatives Other than Cash Flow Hedges

The estimated fair value of derivative contracts by maturity date was as follows (in millions):

	Maturity Periods
	Less than one year		One to two years		More than two years		Total fair value
June 30, 2015	$	10.5	$	4.1	$	—	$	14.6

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Long-Term Debt (Indebtedness Table) (Details) - USD ($) $ in Millions	Jun. 30, 2015	May. 12, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 150.0
Other Long-term Debt	0.3		$ 0.4
Long-term Debt	2,827.2		2,022.5
Partnership [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	150.0		237.0
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 0.0		$ 0.0
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.70%		2.70%
Senior Notes	$ 399.6		$ 399.5
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.125%		7.125%
Senior Notes	$ 182.9		$ 184.4
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.40%		4.40%
Senior Notes	$ 553.0		$ 553.2
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 750.0
Debt Instrument, Interest Rate, Stated Percentage	4.15%	4.15%	0.00%
Senior Notes	$ 748.7		$ 0.0
Selling Priceof Debt Instrument		99.827%
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.60%		5.60%
Senior Notes	$ 349.7		$ 349.7
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 150.0
Debt Instrument, Interest Rate, Stated Percentage	5.05%	5.05%	5.05%
Senior Notes	$ 443.0		$ 298.3
Selling Priceof Debt Instrument		96.381%
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 900.0

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Derivatives (Summary of Derivative Income Expense) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Net fair value of derivatives	$ 14.6		$ 14.6		$ 21.7
Gain (loss) on derivative activity	1.2	$ (1.6)	1.4	$ (2.9)
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivatives	3.6		3.6
Commodity Swap
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives	(2.5)	(1.3)	(6.3)	(2.0)
Realized gain (loss) on derivatives	$ 3.7	$ (0.3)	$ 7.7	$ (0.9)

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Investment in Unconsolidated Affiliate (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries	$ 12.4	$ 3.0	$ 19.2	$ 5.7
Equity in income of equity investments	5.9	4.5	9.7	8.7
Investment in equity investment	261.2		261.2		$ 270.8
Undistributed Earnings, Basic	26.9	7.4	51.0	15.3
Gulf Coast Fractionators [Member]
Schedule of Equity Method Investments [Line Items]
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries	4.2	0.0	6.9	0.0
Equity in income of equity investments	2.9	3.9	6.3	8.0
Investment in equity investment	$ 53.4		$ 53.4		54.1
Ownership Percentage	38.75%		38.75%
Howard Energy Partners [Member]
Schedule of Equity Method Investments [Line Items]
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries	$ 8.2	3.0	$ 12.3	5.7
Equity in income of equity investments	3.0	$ 0.6	3.4	$ 0.7
Investment in equity investment	$ 207.8		$ 207.8		$ 216.7
Ownership Percentage	30.60%		30.60%

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Acquisition Acquisition (Recast) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenues	$ 1,274.5	$ 927.2	$ 2,215.0	$ 1,650.3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	44.6	62.4	69.6	110.9
Net Income (Loss) Attributable to Noncontrolling Interest	28.4	35.7	36.4	42.8
Net Income (Loss) Attributable to Parent	16.2	26.7	33.2	68.1
EnLink Midstream, LLC interest in net income	$ 14.5	28.8	30.8	35.6
ENLC Historical [Member]
Business Acquisition [Line Items]
Revenues		927.2	2,210.8	1,650.3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		64.5	67.2	113.9
Net Income (Loss) Attributable to Noncontrolling Interest		35.7	36.4	42.8
Net Income (Loss) Attributable to Parent		28.8	30.8	71.1
EnLink Midstream, LLC interest in net income		28.8	30.8	35.6
VEX [Member]
Business Acquisition [Line Items]
Revenues		0.0	4.2	0.0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		(2.1)	2.4	(3.0)
Net Income (Loss) Attributable to Noncontrolling Interest		0.0	0.0	0.0
Net Income (Loss) Attributable to Parent		(2.1)	2.4	(3.0)
EnLink Midstream, LLC interest in net income		$ 0.0	$ 0.0	$ 0.0

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Significant Accounting Policies (Notes)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Significant Accounting Policies

(2) Significant Accounting Policies

(a) Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) 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. 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 the Company, as well as the Company'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.

On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to "Devon investment interest in net income" on the Company's Condensed Consolidated Statements of Operations.

(b) Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services through various contractual arrangements which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal, or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the consolidated statements of operations as follows:

• Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above.

• Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Condensed Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holders' share of net income or loss and distributions).

(d) Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the six months ended June 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

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Employee Incentive Plans (Textuals) (Details) - Jun. 30, 2015 - USD ($) $ in Millions	Total	Total
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period		3 years
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period		3 years
Restricted Stock Units (RSUs) | ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 0.4	$ 7.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		261,409
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	0.5	$ 7.5
Restricted Stock Units (RSUs) | ENLK Restricted Unit March Vest [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		128,675
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 3.4
Restricted Stock Units (RSUs) | ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	0.6	$ 8.9
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		258,094
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	0.6	$ 9.2
Restricted Stock Units (RSUs) | ENLC Restricted Units March Vest [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		102,543
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 3.4
Restricted Stock | ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	24.1	$ 24.1
Unrecognized compensation costs, weighted average period for recognition		1 year 11 months
EnLink Midstream Partners, LP | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	3.6	$ 3.6
Unrecognized compensation costs, weighted average period for recognition		2 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		0
EnLink Midstream Partners, LP | 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	24.3	$ 24.3
Unrecognized compensation costs, weighted average period for recognition		2 years
Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units	$ 3.7	$ 3.7
Unrecognized compensation costs, weighted average period for recognition		2 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		0
Minimum [Member] | EnLink Midstream Partners, LP | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		0.00%
Minimum [Member] | Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		0.00%
Maximum [Member] | EnLink Midstream Partners, LP | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		200.00%
Maximum [Member] | Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		200.00%

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Acquisition (Details Textuals) - USD ($) $ in Millions						4 Months Ended	6 Months Ended	12 Months Ended
	Apr. 01, 2015	Mar. 16, 2015	Jan. 31, 2015	Nov. 01, 2014	Oct. 22, 2014	Jun. 30, 2014	Jun. 30, 2015	Dec. 31, 2014	Mar. 07, 2014
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs									$ 51.4
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					1,000,000.0			115,495,669
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable					$ 31.2
Chevron Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs							$ 0.4
Consideration Transferred				$ 231.5
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							16.0
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual							(0.1)
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Finite-Lived Intangible Asset, Useful Life				20 years
LPC [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs							0.2
Consideration Transferred			$ 100.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							559.6
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual							(1.6)
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Finite-Lived Intangible Asset, Useful Life			10 years
Business Combination, Consideration Transferred, Other			$ 78.9
Coronado [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs							3.0
Consideration Transferred		$ 602.1
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							61.5
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual							$ 4.1
Payments to Acquire Businesses, Gross		$ 242.1
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		6,704,285
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Finite-Lived Intangible Asset, Useful Life		10 years
Business Combination, Consideration Transferred, Other		$ 232.5
VEX Pipeline [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 171.0
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	338,159
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$ 9.0
Capitalized Costs, Support Equipment and Facilities	40.0
Business Combination, Historical Cost of Entity Under Common Control	132.7
Distribution To Parent For Asset Drop	$ 38.3
Crosstex Energy Inc. [Domain] [Domain]
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual						$ 968.8
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual						$ 26.5
Common Class C [Member] | Coronado [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		6,704,285
Enlink Midstream, Inc.
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							5.30%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							0.50%
Enlink midstream, LLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest								50.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							100.00%
EnLink Midstream Partners, LP
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							50.00%
Business Acquisition, Percentage of Voting Interests Acquired									50.00%
Class D Common Unit [Member] | EnLink Midstream LP [Member] | Acacia [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | Midstream Holdings [Member] | EnLink Midstream Holdings, LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							9.60%
Midstream Holdings [Member] | Enlink midstream, LLC [Member] | Acacia [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							50.00%
Gulf Coast Fractionators [Member]
Business Acquisition [Line Items]
Ownership Percentage							38.75%

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Affiliate Transactions (Tables)

6 Months Ended

Jun. 30, 2015

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 are settled through an adjustment to equity prior to March 7, 2014 (in millions):

	Six Months Ended June 30, 2014
Continuing Operations:
Revenues - affiliates	$	(436.4	)
Operating cost and expenses - affiliates	340.0
Net affiliate transactions	(96.4		)
Capital expenditures	21.3
Other third-party transactions, net	53.0
Net third-party transactions	74.3
Net cash distributions to Devon - continuing operations	(22.1		)
Non-cash distribution of net assets to Devon	(23.2		)
Total net distributions per equity	$	(45.3	)
Discontinued operations:
Revenues - affiliates	$	(10.4	)
Operating costs and expenses - affiliates	5.0
Net affiliate transactions	(5.4		)
Capital expenditures	0.6
Other third-party transactions, net	0.4
Net third-party transactions	1.0
Net cash distributions to Devon and non-controlling interests - discontinued operations	(4.4		)
Non-cash distribution of net assets to Devon	(39.9		)
Total net distributions per equity	$	(44.3	)
Total distributions- continuing and discontinued operations	$	(89.6	)

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Goodwill and Intangible Assets (Tables)

6 Months Ended

Jun. 30, 2015

Goodwill [Line Items]

Schedule of Goodwill

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

	June 30, 2015		December 31, 2014
	(in millions)
Texas	$	1,185.0	$	1,168.2
Louisiana	786.8		786.8
Oklahoma	190.3		190.3
Crude and Condensate	142.1		112.5
Corporate	1,427.0		1,426.9
Total	$	3,731.2	$	3,684.7

Schedule of Finite-Lived Intangible Assets

The following table represents the Partnership's total purchased intangible assets for the periods stated (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
June 30, 2015
Customer relationships	$	906.8	$	(66.3	)	$	840.5
December 31, 2014
Customer relationships	$	569.5	$	(36.5	)	$	533.0

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

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

2015 (remaining)	$	33.2
2016	66.4
2017	66.4
2018	66.3
2019	65.5
Thereafter	542.7
Total	$	840.5

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Certain Provision of the Partnership Agreement (Textual) (Details) - USD ($)			3 Months Ended			6 Months Ended
	May. 27, 2015	Feb. 17, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Nov. 30, 2014
Subsidiary Sale Of Stock [Line Items]
Proceeds from Issuance of common units						$ 4,100,000	$ 19,900,000
Partners' Capital Account, Units						$ 364,100,000
Percentage Of Avaliable Cash to Distribute			100.00%			100.00%
Distribution Made to Limited Partner, Distribution Period						45 days
General Partner Interest | 13% Distribution
Subsidiary Sale Of Stock [Line Items]
Incentive Distribution Percentage Levels						13.00%
Incentive Distribution, Distribution Per Unit						$ 0.25
General Partner Interest | 23% Distribution
Subsidiary Sale Of Stock [Line Items]
Incentive Distribution Percentage Levels						23.00%
Incentive Distribution, Distribution Per Unit						$ 0.3125
General Partner Interest | 48% Distribution
Subsidiary Sale Of Stock [Line Items]
Incentive Distribution Percentage Levels						48.00%
Incentive Distribution, Distribution Per Unit						$ 0.375
BMO Capital Markets Corp. | EDA [Member]
Subsidiary Sale Of Stock [Line Items]
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement			$ 337,600,000			$ 337,600,000
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 units						4,100,000
Payments of Stock Issuance Costs						100,000
Aggregate Amount Of Equity Securities Allowed Under Equity Distribution Agreement								$ 350,000,000
Partners' Capital Account, Units						$ 200,000
Class E Common Unit [Member]
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit			$ 0.15
Common Class C [Member]
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit				$ 0.38
Class D Common Unit [Member]
Subsidiary Sale Of Stock [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared				$ 0.18
Common Units
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit			$ 0.385	$ 0.38	$ 0.375
Distribution Made to Limited Partner, Distribution Date			Aug. 13, 2015	May 14, 2015	Feb. 12, 2015
EnLink Midstream Holdings, LP [Member] | Midstream Holdings [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream LP [Member] | Acacia [Member]
Subsidiary Sale Of Stock [Line Items]
Related Party Transaction, Ownership Interest Transferred	25.00%	25.00%
Class E Common Unit [Member] [Member] | EnLink Midstream Holdings, LP [Member] | Midstream Holdings [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream LP [Member] | Acacia [Member]
Subsidiary Sale Of Stock [Line Items]
Related Party Transaction, Amounts of Transaction, Shares	36,629,888
Class D Common Unit [Member] | EnLink Midstream Holdings, LP [Member] | Midstream Holdings [Member] | EMH Drop Down [Member] | Affiliated Entity [Member] | EnLink Midstream LP [Member] | Acacia [Member]
Subsidiary Sale Of Stock [Line Items]
Related Party Transaction, Amounts of Transaction, Shares		31,618,311
Common Class C [Member]
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit			$ 0.385
Stock Issued During Period, Shares, Acquisitions						6,704,285
Paid In Kind Dividends			120,622	99,794

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Acquisition (Details) - USD ($) $ in Millions	Mar. 16, 2015	Jan. 31, 2015	Nov. 01, 2014	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Assets acquired [Abstract]
Goodwill				$ 3,731.2	$ 3,684.7	$ 3,693.5
LPC [Member]
Business Acquisition [Line Items]
Consideration Transferred		$ 100.0
Assets acquired [Abstract]
Goodwill		29.6
Current assets (including $21.1 million in cash)		107.4
Property, plant and equipment		29.8
Intangibles		43.2
Liabilities assumed:
Current liabilities		(106.0)
Deferred tax liability		(4.0)
Net assets acquired		$ 100.0
Coronado [Member]
Business Acquisition [Line Items]
Consideration Transferred	$ 602.1
Assets acquired [Abstract]
Goodwill	16.9
Current assets (including $21.1 million in cash)	26.2
Property, plant and equipment	302.1
Intangibles	281.0
Liabilities assumed:
Current liabilities	(24.1)
Net assets acquired	$ 602.1
Chevron Acquisition [Member]
Business Acquisition [Line Items]
Consideration Transferred			$ 231.5
Assets acquired [Abstract]
Property, plant and equipment			225.3
Intangibles			13.0
Liabilities assumed:
Current liabilities			(6.8)
Net assets acquired			$ 231.5

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Indebtedness Table

As of June 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):

	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9% respectively	$	150.0	$	237.0
Company credit facility (due 2019)	—		—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
The Partnership's senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
The Partnership's senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Partnership's Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, 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 $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

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Income Tax (Tables)

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income taxes included in the condensed consolidated financial statements were as follows for the periods presented.

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
	(in millions)
Predecessor income tax expense	$	—	$	—	$	—	$	19.4
ENLC income tax expense	10.2		18.5		20.9		22.8
Total income tax expense	$	10.2	$	18.5	$	20.9	$	42.2

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Organization and Summary of Significant Agreement

6 Months Ended

Jun. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Summary of Significant Agreements

(1) General

In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” and “us,” or like terms, are sometimes used as references to EnLink Midstream, LLC and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP and Midstream Holdings, together with their consolidated subsidiaries. “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization 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. ("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 Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.3% limited partner interest in the Partnership as of June 30, 2015 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). At the conclusion of the mergers, Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 common units to a wholly-owned subsidiary of Devon, which represents approximately 70% of the outstanding limited liability company interests in ENLC. Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to the Partnership in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.6% limited partner interest in the Partnership as of June 30, 2015. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the "May Transferred Interests") to the Partnership in a drop down transaction (the "May EMH Drop Down" and together with the February EMH Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.2% limited partner interest in the Partnership as of June 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See Note (3) - Acquisitions for further discussion.

Our assets consist of equity interests in the Partnership. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. As of June 30, 2015, our interests in the Partnership consist of the following:

•68,248,199 common units representing an aggregate 26.1% limited partner interest in the Partnership; and

• 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. The Partnership's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and its south Louisiana processing plants to its fractionators in south Louisiana. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of arrangements. The Partnership'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. The Partnership also provides a variety of crude oil and condensate services which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucking facilities as well as brine disposal services.

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Certain Provision of the Partnership Agreement (Tables)

6 Months Ended

Jun. 30, 2015

Partners' Capital [Abstract]

Distributions Made to Limited Partner, by Distribution

A summary of the Partnership's distribution activity relating to the common units for the six months ended June 30, 2015 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2014	$	0.375	February 12, 2015
First Quarter of 2015 (1) (2)	$	0.38	May 14, 2015
Second Quarter of 2015 (3)	$	0.385	August 13, 2015

(1) The Partnership declared a partial first quarter 2015 distribution on its Class D Common Units of $0.18 per unit paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.

(2) The Partnership's first quarter distributions on its Class C Common Units of $0.38 per unit were PIK through the issuance of 99,794 Class C Common Units on May 14, 2015.

(3) The Partnership declared a partial second quarter 2015 distribution on its Class E Common Units of $0.15 per unit to be paid on August 13, 2015. Distributions declared for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution

The net income allocated to the General Partner is as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
Income allocation for incentive distributions	$	11.3		$	5.9		$	20.1		$	7.3
Unit-based compensation attributable to ENLC’s restricted units	(3.9		)	(3.1		)	(10.9		)	(3.7		)
General Partner interest in net income	0.2			0.3			0.3			0.4
General Partner interest in drop down transactions	11.5			40.4			36.1			49.9
General Partner share of net income	$	19.1		$	43.5		$	45.6		$	53.9

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures

The following schedule summarizes net income from discontinued operations (in millions):

	Six Months Ended   June 30,
	2014
Revenues:
Revenues	$	6.8
Revenues - affiliates	10.5
Total revenues	17.3
Operating costs and expenses:
Operating expenses	15.7
Total operating costs and expenses	15.7
Income before income taxes	1.6
Income tax provision	0.6
Net income	$	1.0

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	May. 12, 2015	Feb. 05, 2015	Mar. 07, 2014	Feb. 20, 2014
Debt Instrument [Line Items]
Other Long-term Debt	$ 0.3	$ 0.4
Long-term Debt	2,827.2	2,022.5
Line of Credit Facility, Maximum Borrowing Capacity	1,500.0					$ 1,000.0
Line Of Credit Facility, Additional Borrowing Limit	$ 500.0
Line of Credit Facility, Interest Rate During Period	0.50%
Letters of Credit Outstanding, Amount	$ 2.9
Line of Credit Facility, Amount Outstanding	150.0
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,340.0
Percentage Rate	1.00%
Enlink Midstream, Inc.
Debt Instrument [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	5.30%
EnLink Midstream Partners GP, LLC [Member]
Debt Instrument [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	100.00%
Maximum [Member]
Debt Instrument [Line Items]
Leverage ratios	5.0
Conditional acquisition purchase price	$ 50.0
Minimum [Member]
Debt Instrument [Line Items]
Interest Coverge Ratio	2.50
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratios	5.5
Base Rate [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	0.50%
Eurodollar [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	1.00%
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 250.0				$ 250.0
Line of Credit Facility, Amount Outstanding	0.0	$ 0.0
Line of Credit Facility, Remaining Borrowing Capacity	$ 250.0
ENLC Credit Facility [Member] | Enlink Midstream, Inc.
Debt Instrument [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest, Shares	17,431,152
ENLC Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratios	4.00
ENLC Credit Facility [Member] | AcquisitionPeriod [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratios	4.50
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 500.0	$ 125.0
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.125%	7.125%
Senior Notes	$ 182.9	$ 184.4
Debt Instrument, Unamortized Discount (Premium), Net	$ 20.4	$ 21.9
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.70%	2.70%
Senior Notes	$ 399.6	$ 399.5
Debt Instrument, Unamortized Discount (Premium), Net	$ (0.4)	$ (0.5)
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.40%	4.40%
Senior Notes	$ 553.0	$ 553.2
Debt Instrument, Unamortized Discount (Premium), Net	$ 3.0	$ 3.2
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.60%	5.60%
Senior Notes	$ 349.7	$ 349.7
Debt Instrument, Unamortized Discount (Premium), Net	$ (0.3)	$ (0.3)
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.05%	5.05%	5.05%
Senior Notes	$ 443.0	$ 298.3
Debt Instrument, Face Amount			$ 150.0
Debt Instrument, Unamortized Discount (Premium), Net	$ (7.0)	$ (1.7)
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	2.30%	1.90%
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%	0.00%	4.15%
Senior Notes	$ 748.7	$ 0.0
Debt Instrument, Face Amount			$ 750.0
Debt Instrument, Unamortized Discount (Premium), Net	$ (1.3)
Post Amendment [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,500.0
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 900.0
Debt Instrument, Redemption, Period One [Member] | 5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Redemption, Period One [Member] | 4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Redemption, Period Two [Member] | 5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Redemption, Period Two [Member] | 4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%

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Fair Value Measurement (Fair Measurement on a Recurring Nonrecurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Inputs, Level 2 | Commodity Swap | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Fair Value of Derivative	$ 14.6	$ 21.7

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Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 72.0	$ 68.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.4	67.4	139.0
Accrued revenue and other	379.6	253.3
Related party	110.8	121.6
Fair value of derivative assets	14.0	16.7
Natural gas and NGLs inventory, prepaid expenses and other	70.9	48.8
Total current assets	714.7	647.8
Property and equipment, net of accumulated depreciation of $1,585.7 and $1,426.3, respectively	5,550.5	5,042.8
Intangible assets, net of accumulated amortization of $66.3 and $36.5, respectively	840.5	533.0
Goodwill	3,731.2	3,684.7
Fair value of derivative assets	4.9	10.0
Investments in unconsolidated affiliates	261.2	270.8
Other assets, net	25.5	17.6
Total assets	11,128.5	10,206.7
Current liabilities:
Accounts payable and drafts payable	39.1	121.8
Accounts payable to related party	21.6	3.0
Accrued gas, NGLs, condensate and crude oil purchases	316.3	204.5
Fair value of derivative liabilities	3.5	3.0
Other current liabilities	163.0	152.3
Total current liabilities	543.5	484.6
Long-term debt	2,827.2	2,022.5
Fair value of derivative liabilities	0.8	2.0
Asset retirement obligation	12.6	12.4
Other long-term liabilities	75.2	83.8
Deferred tax liability	543.7	526.6
Redeemable non-controlling interest	6.9	0.0
Members' equity	2,743.6	2,774.3
Non-controlling interest	4,375.0	4,196.8
Net Devon investment	0.0	103.7
Total members' equity	$ 7,118.6	$ 7,074.8
Commitment and Contingencies (Note 15)
Total liabilities and members’ equity	$ 11,128.5	$ 10,206.7

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Acquisition (Proforma) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Pro forma total revenues (1)	$ 1,453.4	$ 2,337.2	$ 2,834.6
Pro forma net income	55.2	64.7	74.0
Pro forma net income attributable to EnLink Midstream, LLC	$ 25.3	$ 31.0	$ 42.7
Pro forma net income per common unit: Basic (usd per unit)	$ 0.17	$ 0.18	$ 0.28
Pro forma net income per common unit: Diluted (usd per unit)	$ 0.17	$ 0.18	$ 0.28

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Consolidated Statements of Changes in Members' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Units	Non-Controlling Interest	Devon Energy Corporation
Increase (Decrease) in Members' Equity
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 7,074.8	$ 2,774.3	$ 4,196.8	$ 103.7
Common Stock, Shares, Outstanding		164.1
Unit-based compensation	21.5	$ 11.0	10.5
Issuance of units by the Partnership	364.1		364.1
Conversion of restricted units for common, net of units withheld for taxes	(2.8)	$ (2.8)
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings		0.1
Non-controlling partner's impact of conversion of restricted units	(2.5)		(2.5)
Change in equity due to issuance of units by the partnership	(5.0)	$ 8.5	(13.5)
Non-controlling interest distributions	(175.7)		(175.7)
Non-controlling interest contribution	7.3		7.3
Distributions to members	(79.3)	(79.3)
Tax benefit from vesting of restricted units	1.1	1.1
Adjustment related to mandatory redemption of E2 non-controlling interest	(5.4)		(5.4)
Redeemable non-controlling interest	(6.9)		(6.9)
Contribution from Devon to the Partnership	28.8		2.2	26.6
Distribution To Affiliate	(171.0)		(38.3)	(132.7)
Net income	69.6	30.8	36.4	$ 2.4
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Dec. 31, 2014	0.0
Increase (Decrease) in Temporary Equity
Redeemable Noncontrolling Interest Reclassifications Between Permanen And Temporary Equity	6.9
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2015	6.9
Increase (Decrease) in Members' Equity
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 7,118.6	$ 2,743.6	$ 4,375.0
Common Stock, Shares, Outstanding		164.2		0.0

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Earnings per Unit and Dilution Computations (Unit Weighted Average Schedule) (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Capital Unit [Line Items]
Weighted Average Number of Shares Outstanding, Basic	164.2	164.0	164.2	164.0
Weighted Average Number Diluted Shares Outstanding Adjustment	0.4	0.3	0.4	0.2
Weighted average common shares outstanding: Basic (usd per share)	164.6	164.3	164.6	164.2
Common Units
Capital Unit [Line Items]
Weighted Average Limited Partnership Units Outstanding, Basic	164.2	164.0	164.2	164.0

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Investment in Unconsolidated Affiliate (Tables)

6 Months Ended

Jun. 30, 2015

Schedule of Equity Method Investments [Line Items]

Equity Method Investments

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	Gulf Coast Fractionators		Howard Energy Partners		Total
Three months ended
June 30, 2015
Distributions	$	4.2	$	8.2	$	12.4
Equity in income	$	2.9	$	3.0	$	5.9
June 30, 2014 (1)
Distributions	$	—	$	3.0	$	3.0
Equity in income	$	3.9	$	0.6	$	4.5
Six months ended
June 30, 2015
Distributions	$	6.9	$	12.3	$	19.2
Equity in income	$	6.3	$	3.4	$	9.7
June 30, 2014 (1)
Distributions	$	—	$	5.7	$	5.7
Equity in income	$	8.0	$	0.7	$	8.7

(1) Includes income and distributions for the period from March 7, 2014 through June 30, 2014 for HEP.

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	June 30, 2015		December 31, 2014
Gulf Coast Fractionators	$	53.4	$	54.1
Howard Energy Partners	207.8		216.7
Total investments in unconsolidated affiliates	$	261.2	$	270.8

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Employee Incentive Plans (Intrinsic and Fair Value of Units Vested) (Details) - Jun. 30, 2015 - Restricted Stock Units (RSUs) - USD ($) $ in Millions	Total	Total
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 0.4	$ 7.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	0.5	7.5
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	0.6	8.9
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 0.6	$ 9.2

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure

(15) Commitments and Contingencies

(a) Severance and Change in Control Agreements

Certain members of management of the Partnership are parties to severance and change of control agreements with the General Partner. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such an individual from, among other things, competing with the General Partner or its affiliates during his employment, and disclosing confidential information about, or interfering with a client or customer of, the General Partner or its affiliates during his employment and for a certain period of time following the termination of such person’s employment.

(b) 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.

(c) Litigation Contingencies

The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows. 

At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows.

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. 

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana.  The amount of damages is unspecified. The Partnership's subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area.  On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC ("Texas Brine"), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses.  The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputed the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23^rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

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.

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Employee Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule Of Share Based Payment Award Other Than Stock Options Valuation Assumption

The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream, LLC Performance Units:	2015
Beginning TSR Price	$	34.24
Risk-free interest rate	0.99		%
Volatility factor	33.02		%
Distribution yield	2.98		%

The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream Partners, LP Performance Units:	2015
Beginning TSR Price	$	27.68
Risk-free interest rate	0.99		%
Volatility factor	33.01		%
Distribution yield	5.66		%

Schedule of Nonvested Performance-based Units Activity

The following table presents a summary of the Company's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	105,080		40.5
Vested	—		—
Non-vested, end of period	105,080		$	40.5
Aggregate intrinsic value, end of period (in millions)	$	3.3

The following table presents a summary of the Partnership's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	118,126		35.41
Vested	—		—
Non-vested, end of period	118,126		$	35.41
Aggregate intrinsic value, end of period (in millions)	$	2.6

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

The Partnership and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Cost of unit-based compensation allocated to Predecessor general and     administrative expense (1)	$	—	$	—	$	—	$	2.8
Cost of unit-based compensation charged to general and administrative     expense	6.6		5.0		18.5		6.0
Cost of unit-based compensation charged to operating expense	1.1		0.8		3.0		1.0
Total amount charged to income	$	7.7	$	5.8	$	21.5	$	9.8
Interest of non-controlling partners in unit-based compensation	$	3.7	$	2.5	$	9.2	$	3.0
Amount of related income tax benefit recognized in income	$	1.5	$	1.3	$	4.6	$	2.6

(1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity in 2014.

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

A summary of the restricted incentive unit activity for the six months ended June 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,022,191			$	31.25
Granted	564,524			27.05
Vested*	(261,409		)	28.76
Forfeited	(62,451		)	31.09
Non-vested, end of period	1,262,855			$	29.89
Aggregate intrinsic value, end of period (in millions)	$	27.7

 * Vested units include 89,679 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units activity for the six months endedJune 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	986,472			$	37.03
Granted	481,042			31.74
Vested*	(258,094		)	35.79
Forfeited	(53,723		)	36.15
Non-vested, end of period	1,155,697			$	35.15
Aggregate intrinsic value, end of period (in millions)	$	35.9

 * Vested units include 82,352 units withheld for payroll taxes paid on behalf of employees.

Schedule of Share Based Compensation Restricted Stock and Restricted Stock Units Vested and Fair Value Vested

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended June 30,		Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.6	$	8.9
Fair value of units vested	$	0.6	$	9.2

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended    June 30,		Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.4	$	7.2
Fair value of units vested	$	0.5	$	7.5

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Discontinued Operations

6 Months Ended

Jun. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

(17) 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 economic benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

The following schedule summarizes net income from discontinued operations (in millions):

	Six Months Ended   June 30,
	2014
Revenues:
Revenues	$	6.8
Revenues - affiliates	10.5
Total revenues	17.3
Operating costs and expenses:
Operating expenses	15.7
Total operating costs and expenses	15.7
Income before income taxes	1.6
Income tax provision	0.6
Net income	$	1.0

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Derivatives (Schedule of Derivative Assets Liabilities) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Fair value of derivative assets — current	$ 14.0	$ 16.7
Fair value of derivative assets — long term	4.9	10.0
Fair value of derivative liabilities — current	(3.5)	(3.0)
Fair value of derivative liabilities — long term	(0.8)	(2.0)
Net fair value of derivatives	14.6	$ 21.7
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Net fair value of derivatives	$ 14.6

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Statement of Cash Flows [Abstract]
Net income from continuing operations	$ 69.6	$ 109.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	189.0	123.5
Accretion expense	0.3	0.3
Gain on extinguishment of debt	0.0	(0.8)
Deferred tax expense	17.8	41.5
Non-cash unit-based compensation	21.5	7.0
(Gain) loss on derivatives recognized in net income	(5.0)	2.9
Cash settlements on derivatives	11.3	(0.9)
Amortization of debt issue costs	1.5	0.4
Amortization of premium on notes	(1.5)	(1.0)
Redeemable non-controlling interest expense	(3.3)	0.0
Distribution of earnings from equity investment	10.3	0.7
Equity in income from equity investments	(9.7)	(8.7)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	57.3	(10.5)
Natural gas and NGLs inventory, prepaid expenses and other	(26.6)	(15.3)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(55.5)	(45.8)
Net cash provided by operating activities	277.0	203.2
Cash flows from investing activities:
Additions to property and equipment	(349.2)	(336.7)
Acquisition of business, net of cash acquired	(324.8)	(126.0)
Proceeds from sale of property	0.1	0.0
Investment in limited liability company	0.0	(5.7)
Distribution from equity investment company in excess of earnings	8.9	5.0
Net cash used in investing activities	(665.0)	(463.4)
Cash flows from financing activities:
Proceeds from borrowings	2,327.4	1,732.2
Payments on borrowings	(1,521.2)	(1,490.2)
Payments on capital lease obligations	(1.6)	(1.2)
Increase (decrease) in drafts payable	(12.4)	8.6
Debt financing costs	(9.5)	(7.4)
Conversion of restricted units, net of units withheld for taxes	(2.8)	0.0
Conversion of Partnership's restricted units, net of units withheld for taxes	(2.5)	0.0
Proceeds from issuance of Partnership's common units	4.1	19.9
Proceeds from exercise of Partnership unit options	0.0	0.3
Distribution to non-controlling partners	(175.7)	(45.8)
Distribution to Members	79.3	14.7
Contribution from Devon	28.8	95.3
Distribution to Devon for net assets acquired (Note 3)	(171.0)	0.0
Contributions by non-controlling interest	7.3	1.2
Distributions to Predecessor	0.0	(22.1)
Net cash provided by financing activities	391.6	276.1
Net cash provided by operating activities	0.0	5.0
Net cash used in investing activities	0.0	(0.6)
Net cash used in financing activities – net distributions to Devon and non-controlling interests	0.0	(4.4)
Net cash provided by discontinued operations	0.0	0.0
Net increase in cash and cash equivalents	3.6	15.9
Cash and cash equivalents, start of period	68.4	0.0
Cash and cash equivalents, end of period	72.0	15.9
Cash paid for interest	44.4	17.1
Cash paid for income taxes	$ 13.4	$ 6.9

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Assets, Noncurrent [Abstract]
Allowance for bad debt	$ 0.4	$ 0.0
Property and equipment, accumulated depreciation	1,585.7	1,426.3
Intangible assets, accumulated amortization	$ 66.3	$ 36.5

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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure

(10)Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligation:

	June 30, 2015			June 30, 2014
	(in millions)
Beginning asset retirement obligation	$	20.6		$	8.1
Revisions to existing liabilities	(4.0		)	3.4
Liabilities acquired	—			0.5
Accretion	0.3			0.3
Liabilities settled	(3.2		)	—
Ending asset retirement obligation	$	13.7		$	12.3

Asset retirement obligations of $1.1 million and $8.2 million as of June 30, 2015 and December 31, 2014, respectively, are included in Other Current Liabilities.

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 24, 2015
Document Information [Line Items]
Document Type	10-Q
Document Fiscal Period Focus	Q2
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Amendment Flag	false
Entity Registrant Name	EnLink Midstream, LLC
Entity Central Index Key	0001592000
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		164,231,749

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Investment in Unconsolidated Affiliate

6 Months Ended

Jun. 30, 2015

Equity Method Investments and Joint Ventures [Abstract]

Investment in unconsolidated affiliate

(11) Investment in Unconsolidated Affiliates

The Partnership's unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in GCF at June 30, 2015 and 2014 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at June 30, 2015 and 2014.

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	Gulf Coast Fractionators		Howard Energy Partners		Total
Three months ended
June 30, 2015
Distributions	$	4.2	$	8.2	$	12.4
Equity in income	$	2.9	$	3.0	$	5.9
June 30, 2014 (1)
Distributions	$	—	$	3.0	$	3.0
Equity in income	$	3.9	$	0.6	$	4.5
Six months ended
June 30, 2015
Distributions	$	6.9	$	12.3	$	19.2
Equity in income	$	6.3	$	3.4	$	9.7
June 30, 2014 (1)
Distributions	$	—	$	5.7	$	5.7
Equity in income	$	8.0	$	0.7	$	8.7

(1) Includes income and distributions for the period from March 7, 2014 through June 30, 2014 for HEP.

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

	June 30, 2015		December 31, 2014
Gulf Coast Fractionators	$	53.4	$	54.1
Howard Energy Partners	207.8		216.7
Total investments in unconsolidated affiliates	$	261.2	$	270.8

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Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Product sales	$ 956.2	$ 687.9	$ 1,626.9	$ 901.3
Product sales - affiliates	31.7	0.0	47.9	436.4
Midstream services	135.9	67.1	238.3	86.2
Midstream services - affiliates	149.5	173.8	300.5	229.3
Gain (loss) on derivative activity	1.2	(1.6)	1.4	(2.9)
Total revenues	1,274.5	927.2	2,215.0	1,650.3
Operating costs and expenses:
Cost of sales (1)	968.2	661.9	1,625.6	1,200.8
Operating expenses (2)	109.1	73.9	207.6	120.6
General and administrative (3)	28.1	26.6	70.8	42.5
Depreciation and amortization	97.7	75.0	189.0	123.5
Total operating costs and expenses	1,203.1	837.4	2,093.0	1,487.4
Operating income	71.4	89.8	122.0	162.9
Other income (expense):
Interest expense, net of interest income	(22.6)	(14.1)	(41.7)	(19.5)
Equity in income of equity investment	5.9	4.5	9.7	8.7
Gain on extinguishment of debt	0.0	0.8	0.0	0.8
Other income (expense)	0.1	(0.1)	0.5	(0.8)
Total other expense	(16.6)	(8.9)	(31.5)	(10.8)
Income from continuing operations before non-controlling interest and income taxes	54.8	80.9	90.5	152.1
Income tax provision	(10.2)	(18.5)	(20.9)	(42.2)
Net income from continuing operations	44.6	62.4	69.6	109.9
Discontinued Operations:
Income from discontinued operations, net of tax	0.0	0.0	0.0	1.0
Discontinued operations, net of tax	0.0	0.0	0.0	1.0
Net income	44.6	62.4	69.6	110.9
Net income attributable to the non-controlling interest	28.4	35.7	36.4	42.8
Net income attributable to EnLink Midstream, LLC	16.2	26.7	33.2	68.1
Predecessor interest in net income (4)	0.0	0.0	0.0	35.5
Devon investment interest in net income	1.7	(2.1)	2.4	(3.0)
EnLink Midstream, LLC interest in net income	$ 14.5	$ 28.8	$ 30.8	$ 35.6
Net income attributable to EnLink Midstream Partners, LP per limited partners' unit:
Basic per common unit	$ 0.09	$ 0.18	$ 0.19	$ 0.22
Diluted per common unit	$ 0.09	$ 0.18	$ 0.19	$ 0.22

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Affiliate Transactions

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and six months ended June 30, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 14.2% and 15.7% of the Partnership's revenues for the three and six months ended June 30, 2015, respectively, and 18.7% and 40.3% for the three and six months ended June 30, 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $112.2 million as of June 30, 2015 and $121.6 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $21.6 million as of June 30, 2015 and $3.0 million as of December 31, 2014. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

Gathering, Processing and Transportation Agreements with Devon

As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  On January 1, 2014, in connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings ("EnLink Midstream Services"), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon ("Gas Services"), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering systems in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.

Effective December 1, 2014, Gas Services assigned one of its 10-year gathering and processing agreements to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, beginning on December 1, 2014, Linn Energy began performing Gas Services' obligations under the applicable agreement, which relates to production dedicated to our Northridge assets in southeastern Oklahoma and remains in full force and effect.

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon.  The terms of these agreements vary, but the agreements expire between July 2015 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee.  These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline.

Transition Services Agreement

In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.1 million for the three and six months ended June 30, 2015 and $1.1 million and $1.3 million for the three and six months ended June 30, 2014, respectively. We received $0.2 million from Devon under the transition services agreement for the six months ended June 30, 2015. Substantially all services under the transition services agreement were completed during 2014.

EMH Drop Down to Partnership

On February 17, 2015, Acacia contributed the February Transferred Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015, which was the first business day following the record date for distribution payments with respect to the distribution for the quarter ended June 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

E2 Drop Down to Partnership

On October 22, 2014, EMI contributed its equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) to the Partnership in a drop down transaction (the "E2 Drop Down"). The total consideration for the transaction was approximately $194.0 million, including a cash payment of $163.0 million and the issuance of approximately 1.0 million Partnership units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the Partnership's units).

Predecessor Affiliate Transactions

Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates.

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

	Six Months Ended June 30, 2014
Continuing Operations:
Revenues - affiliates	$	(436.4	)
Operating cost and expenses - affiliates	340.0
Net affiliate transactions	(96.4		)
Capital expenditures	21.3
Other third-party transactions, net	53.0
Net third-party transactions	74.3
Net cash distributions to Devon - continuing operations	(22.1		)
Non-cash distribution of net assets to Devon	(23.2		)
Total net distributions per equity	$	(45.3	)
Discontinued operations:
Revenues - affiliates	$	(10.4	)
Operating costs and expenses - affiliates	5.0
Net affiliate transactions	(5.4		)
Capital expenditures	0.6
Other third-party transactions, net	0.4
Net third-party transactions	1.0
Net cash distributions to Devon and non-controlling interests - discontinued operations	(4.4		)
Non-cash distribution of net assets to Devon	(39.9		)
Total net distributions per equity	$	(44.3	)
Total distributions- continuing and discontinued operations	$	(89.6	)

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the six months ended June 30, 2014. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the six months ended June 30, 2014. These amounts are included in general and administrative expenses in the accompanying statements of operations.

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Goodwill and Intangible Assets

6 Months Ended

Jun. 30, 2015

Goodwill [Line Items]

Goodwill Disclosure

(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company evaluates goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. 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 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 performed its annual impairment test of goodwill as of the fourth quarter of 2014. 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.

	June 30, 2015		December 31, 2014
	(in millions)
Texas	$	1,185.0	$	1,168.2
Louisiana	786.8		786.8
Oklahoma	190.3		190.3
Crude and Condensate	142.1		112.5
Corporate	1,427.0		1,426.9
Total	$	3,731.2	$	3,684.7

The change in goodwill is related to an increase of $29.6 million attributable to the acquisition of LPC, which is included in the Crude and Condensate segment, and an increase of $16.9 million attributable to the acquisition of Coronado, which is included in the Texas segment. See Note 3-Acquisitions for further discussion.

Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from five to twenty years.

The following table represents the Partnership's total purchased intangible assets for the periods stated (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
June 30, 2015
Customer relationships	$	906.8	$	(66.3	)	$	840.5
December 31, 2014
Customer relationships	$	569.5	$	(36.5	)	$	533.0

The weighted average amortization period for intangible assets is 11.2 years. Amortization expense for intangibles was approximately $18.2 million and $11.3 million for the three months ended June 30, 2015 and 2014, respectively, and $29.7 million and $13.0 million for the six months ended June 30, 2015 and 2014, respectively.

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

2015 (remaining)	$	33.2
2016	66.4
2017	66.4
2018	66.3
2019	65.5
Thereafter	542.7
Total	$	840.5

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Segment Information

6 Months Ended

Jun. 30, 2015

Segment Reporting [Abstract]

Segment Information

(16) Segment Information

Identification of the majority of the Company's operating segments is based principally upon geographic regions served.  The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas ("Texas"), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana ("Louisiana"), natural gas gathering and processing operations located throughout Oklahoma ("Oklahoma") and crude rail, truck, pipeline, and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley ("Crude and Condensate"). The Company's Crude and Condensate segment, which is identified based upon the nature of services provided to customers of the segment, has historically been referred to as the Company's ORV segment. Due to the growth in this segment, including the acquisitions of LPC and VEX, the Company has renamed this segment to more accurately reflect the assets included therein. The Company has restated the prior period to include certain crude and condensate activity in the Crude and Condensate segment. Operating activity for intersegment eliminations is shown in the corporate segment.  The Company’s sales are derived from external domestic customers.

Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and investments in HEP and GCF. The Company evaluates the performance of its operating segments based on operating revenues and segment profits.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
	(In millions)
Three Months Ended June 30, 2015
Product sales	$	81.2		$	401.2		$	0.1		$	473.7		$	—		$	956.2
Product sales-affiliates	35.0			17.0			1.7			14.0			(36.0		)	31.7
Midstream services	36.0			63.2			9.8			26.9			—			135.9
Midstream services-affiliates	115.8			0.3			29.1			4.3			—			149.5
Cost of sales	(118.4		)	(418.2		)	(2.0		)	(465.6		)	36.0			(968.2		)
Operating expenses	(45.5		)	(27.2		)	(9.1		)	(27.3		)	—			(109.1		)
Gain on derivative activity	—			—			—			—			1.2			1.2
Segment profit	$	104.1		$	36.3		$	29.6		$	26.0		$	1.2		$	197.2
Depreciation and amortization	$	(42.8	)	$	(26.9	)	$	(11.8	)	$	(14.5	)	$	(1.7	)	$	(97.7	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	80.9		$	14.7		$	12.3		$	54.4		$	2.5		$	164.8
Three Months Ended June 30, 2014
Product sales	$	68.6		$	514.2		$	—		$	105.1		$	—		$	687.9
Product sales-affiliates	19.3			1.7			—			—			(21.0		)	—
Midstream services	14.6			37.9			—			14.6			—			67.1
Midstream services-affiliates	126.6			—			47.2			—			—			173.8
Cost of sales	(76.1		)	(508.1		)	—			(98.7		)	21.0			(661.9		)
Operating expenses	(38.6		)	(16.5		)	(7.3		)	(11.5		)	—			(73.9		)
Loss on derivative activity	—			—			—			—			(1.6		)	(1.6		)
Segment profit	$	114.4		$	29.2		$	39.9		$	9.5		$	(1.6	)	$	191.4
Depreciation and amortization	$	(32.8	)	$	(19.1	)	$	(11.6	)	$	(10.7	)	$	(0.8	)	$	(75.0	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	75.4		$	121.2		$	(2.2	)	$	33.9		$	3.2		$	231.5

Six Months Ended June 30, 2015
Product sales	$	131.0		$	773.4		$	0.1		$	722.4		$	—		$	1,626.9
Product sales-affiliates	60.9			24.1			5.4			14.0			(56.5		)	47.9
Midstream services	55.6			121.1			20.5			41.1			—			238.3
Midstream services-affiliates	231.3			0.4			60.3			8.5			—			300.5
Cost of sales	(185.6		)	(789.1		)	(7.1		)	(700.3		)	56.5			(1,625.6		)
Operating expenses	(92.6		)	(51.5		)	(16.1		)	(47.4		)	—			(207.6		)
Gain on derivative activity	—			—			—			—			1.4			1.4
Segment profit	$	200.6		$	78.4		$	63.1		$	38.3		$	1.4		$	381.8
Depreciation and amortization	$	(79.2	)	$	(54.4	)	$	(25.3	)	$	(26.9	)	$	(3.2	)	$	(189.0	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	1,427.0		$	3,731.2
Capital expenditures	$	154.4		$	29.9		$	17.5		$	132.0		$	6.7		$	340.5
Six Months Ended June 30, 2014
Product sales	$	114.5		$	649.1		$	11.5		$	126.2		$	—		$	901.3
Product sales-affiliates	311.9			2.3			147.9			—			(25.7		)	436.4
Midstream services	19.5			48.4			—			18.3			—			86.2
Midstream services-affiliates	167.0			—			62.3			—			—			229.3
Cost of sales	(333.4		)	(641.6		)	(133.9		)	(117.6		)	25.7			(1,200.8		)
Operating expenses	(70.3		)	(21.6		)	(14.0		)	(14.7		)	—			(120.6		)
Loss on derivative activity	—			—			—			—			(2.9		)	(2.9		)
Segment profit	$	209.2		$	36.6		$	73.8		$	12.2		$	(2.9	)	$	328.9
Depreciation and amortization	$	(60.1	)	$	(24.3	)	$	(25.8	)	$	(12.4	)	$	(0.9	)	$	(123.5	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	118.0		$	1,430.4		$	3,693.5
Capital expenditures	$	100.5		$	143.3		$	8.0		$	45.0		$	8.7		$	305.5

The table below presents information about segment assets as of June 30, 2015 and December 31, 2014:

	June 30, 2015		December 31, 2014
Segment Identifiable Assets:	(In millions)
Texas	$	4,011.7	$	3,303.0
Louisiana	3,195.5		3,316.5
Oklahoma	885.5		892.8
Crude and Condensate	1,210.6		871.9
Corporate	1,825.2		1,822.5
Total identifiable assets	$	11,128.5	$	10,206.7

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

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
Segment profits	$	197.2		$	191.4		$	381.8		$	328.9
General and administrative expenses	(28.1		)	(26.6		)	(70.8		)	(42.5		)
Depreciation and amortization	(97.7		)	(75.0		)	(189.0		)	(123.5		)
Operating income	$	71.4		$	89.8		$	122.0		$	162.9

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Employee Incentive Plans

6 Months Ended

Jun. 30, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employee Incentive Plans

(12) Employee Incentive Plans

(a)Long-Term Incentive Plans

The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements.

The Partnership and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Cost of unit-based compensation allocated to Predecessor general and     administrative expense (1)	$	—	$	—	$	—	$	2.8
Cost of unit-based compensation charged to general and administrative     expense	6.6		5.0		18.5		6.0
Cost of unit-based compensation charged to operating expense	1.1		0.8		3.0		1.0
Total amount charged to income	$	7.7	$	5.8	$	21.5	$	9.8
Interest of non-controlling partners in unit-based compensation	$	3.7	$	2.5	$	9.2	$	3.0
Amount of related income tax benefit recognized in income	$	1.5	$	1.3	$	4.6	$	2.6

(1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity in 2014.

(b)  EnLink Midstream Partners, LP Restricted Incentive Units

The Partnership's 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 six months ended June 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,022,191			$	31.25
Granted	564,524			27.05
Vested*	(261,409		)	28.76
Forfeited	(62,451		)	31.09
Non-vested, end of period	1,262,855			$	29.89
Aggregate intrinsic value, end of period (in millions)	$	27.7

 * Vested units include 89,679 units withheld for payroll taxes paid on behalf of employees.

The Partnership issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2015, the Partnership issued 128,675 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended    June 30,		Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.4	$	7.2
Fair value of units vested	$	0.5	$	7.5

As of June 30, 2015, there was $24.3 million of unrecognized compensation cost related to non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 2.0 years.

(c)EnLink Midstream Partners, LP Performance Units

In March 2015, the Partnership and ENLC granted performance awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the "GP Plan") and the 2014 Long-Term Incentive Plan (the “LLC Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding the Partnership and the Company (collectively, "EnLink"), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (the “EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership and the designated peer group; (iii) an estimated ranking of the Partnership among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream Partners, LP Performance Units:	2015
Beginning TSR Price	$	27.68
Risk-free interest rate	0.99		%
Volatility factor	33.01		%
Distribution yield	5.66		%

The following table presents a summary of the Partnership's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream Partners, LP Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	118,126		35.41
Vested	—		—
Non-vested, end of period	118,126		$	35.41
Aggregate intrinsic value, end of period (in millions)	$	2.6

As of June 30, 2015 there was $3.6 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

(d)EnLink Midstream, LLC’s Restricted Incentive Units

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 units activity for the six months endedJune 30, 2015 is provided below:

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	986,472			$	37.03
Granted	481,042			31.74
Vested*	(258,094		)	35.79
Forfeited	(53,723		)	36.15
Non-vested, end of period	1,155,697			$	35.15
Aggregate intrinsic value, end of period (in millions)	$	35.9

 * Vested units include 82,352 units withheld for payroll taxes paid on behalf of employees.

ENLC issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding. In March 2015, ENLC issued 102,543 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2015 are provided below (in millions):

	Three Months Ended June 30,		Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2015		2015
Aggregate intrinsic value of units vested	$	0.6	$	8.9
Fair value of units vested	$	0.6	$	9.2

As of June 30, 2015, there was $24.1 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted average period of 1.9 years.

(e) EnLink Midstream, LLC's Performance Units

In March 2015, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC and the designated peer group; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.

EnLink Midstream, LLC Performance Units:	2015
Beginning TSR Price	$	34.24
Risk-free interest rate	0.99		%
Volatility factor	33.02		%
Distribution yield	2.98		%

The following table presents a summary of the Company's performance units.

	Six Months Ended   June 30, 2015
EnLink Midstream, LLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	105,080		40.5
Vested	—		—
Non-vested, end of period	105,080		$	40.5
Aggregate intrinsic value, end of period (in millions)	$	3.3

As of June 30, 2015 there was $3.7 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

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Certain Provision of the Partnership Agreement

6 Months Ended

Jun. 30, 2015

Partners' Capital [Abstract]

Certain Provisions of the Partnership Agreement

(8)  Certain Provisions of the Partnership Agreement

(a) Issuance of Common Units

In November 2014, the 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 from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the six months ended June 30, 2015, the Partnership sold an aggregate of 0.2 million common units under the BMO EDA, generating proceeds of approximately $4.1 million (net of less than $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2015, approximately $337.6 million remains available to be issued under the agreement.

(b) Class C Common Units

In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. For further discussion see Note 3- Acquisitions. The Class C Common Units are substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units may be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on the earlier to occur of (i) the date on which the General Partner, in its sole discretion, determines to convert all of the outstanding Class C Common Units into common units and (ii) the first business day following the date of the distribution for the quarter ended March 31, 2016. Distributions on the Class C Common Units for the three months ended March 31, 2015 were paid-in-kind ("PIK") through the issuance of 99,794 Class C Common Units on May 14, 2015. A distribution on the Class C Common Units of $0.385 per unit was declared for the three months ended June 30, 2015, which will result in the issuance of 120,622 additional Class C Common Units on August 13, 2015.

(c) Class D Common Units

In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion see Note 3 - Acquisitions. The Partnership’s Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. The Partnership’s Class D Common Units automatically converted into the Partnership’s common units on a one-for-one basis on May 4, 2015.

(d) Class E Common Units

In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion see Note 5 - Affiliate Transactions. The Partnership’s Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015.

(e)  Distributions

Unless restricted by the terms of the Partnership's credit facility and/or the indentures governing the Partnership’s senior unsecured notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to its general partner or incentive distributions with respect to the Class C Common Units issued in kind.

Under the quarterly incentive distribution provisions, generally the Partnership's General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit.

A summary of the Partnership's distribution activity relating to the common units for the six months ended June 30, 2015 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2014	$	0.375	February 12, 2015
First Quarter of 2015 (1) (2)	$	0.38	May 14, 2015
Second Quarter of 2015 (3)	$	0.385	August 13, 2015

(1) The Partnership declared a partial first quarter 2015 distribution on its Class D Common Units of $0.18 per unit paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.

(2) The Partnership's first quarter distributions on its Class C Common Units of $0.38 per unit were PIK through the issuance of 99,794 Class C Common Units on May 14, 2015.

(3) The Partnership declared a partial second quarter 2015 distribution on its Class E Common Units of $0.15 per unit to be paid on August 13, 2015. Distributions declared for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

(f) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 8(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
Income allocation for incentive distributions	$	11.3		$	5.9		$	20.1		$	7.3
Unit-based compensation attributable to ENLC’s restricted units	(3.9		)	(3.1		)	(10.9		)	(3.7		)
General Partner interest in net income	0.2			0.3			0.3			0.4
General Partner interest in drop down transactions	11.5			40.4			36.1			49.9
General Partner share of net income	$	19.1		$	43.5		$	45.6		$	53.9

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

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Asset Retirement Obligation (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Current	$ 1.1		$ 8.2
Asset Retirement Obligation	13.7	$ 12.3	$ 20.6	$ 8.1
Revisions to existing liabilities	(4.0)	3.4
Liabilities acquired	0.0	0.5
Accretion	0.3	0.3
Asset Retirement Obligation, Liabilities Settled	$ (3.2)	$ 0.0

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Long-Term Debt

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

(6) Long-Term Debt

As of June 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):

	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9% respectively	$	150.0	$	237.0
Company credit facility (due 2019)	—		—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
The Partnership's senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
The Partnership's senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Partnership's Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, 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 $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

Company Credit Facility

On March 7, 2014, the Company entered into a $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 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 and (iii) 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 June 30, 2015 there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility

On February 20, 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership is permitted to, (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership credit facility by an additional amount not to exceed $500 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year. 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 be increased 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.

As of June 30, 2015, there were $2.9 million in outstanding letters of credit and $150.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms of the Partnership credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”) at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

Prior to March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, at any time in whole, or from time to time in part, at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 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, in either case, 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.

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Income Tax Income Tax (Notes)

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Tax Disclosure

(7)  Income Taxes

Income taxes included in the condensed consolidated financial statements were as follows for the periods presented.

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
	(in millions)
Predecessor income tax expense	$	—	$	—	$	—	$	19.4
ENLC income tax expense	10.2		18.5		20.9		22.8
Total income tax expense	$	10.2	$	18.5	$	20.9	$	42.2

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Earnings per Unit and Dilution Computations

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Earnings per Unit and Dilution Computations

(9) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested unit-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders.

The following table reflects the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 (in millions, except per unit amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
EnLink Midstream, LLC interest in net income	$	14.5		$	28.8		$	30.8		$	35.6
Distributed earnings allocated to:
Common units (1) (2)	$	41.1		$	36.1		$	81.3		$	50.6
Unvested restricted units (1)	0.3			0.1			0.5			0.3
Total distributed earnings	$	41.4		$	36.2		$	81.8		$	50.9
Undistributed loss allocated to:
Common units	$	(26.7	)	$	(7.4	)	$	(50.7	)	$	(15.2	)
Unvested restricted units	(0.2		)	—			(0.3		)	(0.1		)
Total undistributed loss	$	(26.9	)	$	(7.4	)	$	(51.0	)	$	(15.3	)
Net income allocated to:
Common units	$	14.4		$	28.7		$	30.6		$	35.4
Unvested restricted units	0.1			0.1			0.2			0.2
Total net income	$	14.5		$	28.8		$	30.8		$	35.6
Total basic and diluted net income per unit:
Basic	$	0.09		$	0.18		$	0.19		$	0.22
Diluted	$	0.09		$	0.18		$	0.19		$	0.22

__________________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

(1) Three months ended June 30, 2015 and 2014 represents a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and declared distribution of $0.22 per unit for common units paid on August 14, 2014.

(2) Six months ended June 30, 2015 and 2014 represents a distribution of $0.245 per unit paid in May 2015 and a declared distribution of $0.25 per unit for common units payable on August 14, 2015 and a distribution of $0.18 per unit paid in May 2014 and a distribution of $0.22 per unit for common units paid on August 14, 2014. Additionally, six months ended June 30, 2014 includes declared distribution of $0.05 per unit for Class B Common Units paid on May 15, 2014.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014*
Basic and diluted earnings per unit:
Weighted average common units outstanding	164.2	164.0	164.2	164.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	164.2	164.0	164.2	164.0
Dilutive effect of restricted units issued	0.4	0.3	0.4	0.2
Total weighted average diluted common units outstanding	164.6	164.3	164.6	164.2

_______________________________________________

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.

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Employee Incentive Plans (Compensation Schedule) (Details) - Jun. 30, 2015 - USD ($) $ / shares in Units, $ in Millions	Total
ENLK Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	1,022,191
Granted (Units)	564,524
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(261,409)
Forfeited (Units)	(62,451)
Non-vested, end of period (Units)	1,262,855
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$ 31.25
Granted (usd per share)	27.05
Vested (usd per share)	28.76
Forfeited (usd per share)	31.09
Non-vested, end of period (usd per share)	$ 29.89
Aggregate intrinsic value, end of period (in millions)	$ 27.7
Units withheld for payroll taxes on behalf of employees	89,679
ENLC Restricted Units
Weighted Average Grant-Date Fair Value
Units withheld for payroll taxes on behalf of employees	82,352
ENLC Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	986,472
Granted (Units)	481,042
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(258,094)
Forfeited (Units)	(53,723)
Non-vested, end of period (Units)	1,155,697
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$ 37.03
Granted (usd per share)	31.74
Vested (usd per share)	35.79
Forfeited (usd per share)	36.15
Non-vested, end of period (usd per share)	$ 35.15
Aggregate intrinsic value, end of period (in millions)	$ 35.9
Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Number of Units
Non-vested, beginning of period (Units)	0
Granted (Units)	105,080
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Non-vested, end of period (Units)	105,080
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$ 0.00
Granted (usd per share)	40.50
Vested (usd per share)	0.00
Non-vested, end of period (usd per share)	$ 40.50
Aggregate intrinsic value, end of period (in millions)	$ 3.3
EnLink Midstream Partners, LP | Performance Based Restricted Unit [Member]
Number of Units
Non-vested, beginning of period (Units)	0
Granted (Units)	118,126
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Non-vested, end of period (Units)	118,126
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share)	$ 0.00
Granted (usd per share)	35.41
Vested (usd per share)	0.00
Non-vested, end of period (usd per share)	$ 35.41
Aggregate intrinsic value, end of period (in millions)	$ 2.6

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Employee Incentive Plans Total Shareholder Return Unit Summary (Details) - 6 months ended Jun. 30, 2015 - $ / shares	Total
ENLC Restricted Units | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 11 months
Enlink midstream, LLC [Member] | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement Grant Date Fair Value	$ 34.24
Fair Value Assumptions, Risk Free Interest Rate	0.99%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	33.02%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	2.98%
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 6 months
EnLink Midstream Partners, LP | Performance Based Restricted Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement Grant Date Fair Value	$ 27.68
Fair Value Assumptions, Risk Free Interest Rate	0.99%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	33.01%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	5.66%
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 6 months

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Employee Incentive Plans (Expense Schedule) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 7.7	$ 5.8	$ 21.5	$ 9.8
Amount of related income tax expense recognized in income	1.5	1.3	4.6	2.6
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	6.6	5.0	18.5	6.0
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	1.1	0.8	3.0	1.0
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	3.7	2.5	9.2	3.0
Predecessor [Member] | General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 0.0	$ 0.0	$ 0.0	$ 2.8

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Asset Retirement Obligation (Table)

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The schedule below summarizes the changes in the Partnership’s asset retirement obligation:

	June 30, 2015			June 30, 2014
	(in millions)
Beginning asset retirement obligation	$	20.6		$	8.1
Revisions to existing liabilities	(4.0		)	3.4
Liabilities acquired	—			0.5
Accretion	0.3			0.3
Liabilities settled	(3.2		)	—
Ending asset retirement obligation	$	13.7		$	12.3

Asset retirement obligations of $1.1 million and $8.2 million as of June 30, 2015 and December 31, 2014, respectively, are included in Other Current Liabilities.

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Affiliate Transactions (Details) - USD ($) $ in Millions				3 Months Ended		6 Months Ended		12 Months Ended
	May. 27, 2015	Feb. 17, 2015	Oct. 22, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Related Party Transaction [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable			$ 31.2
Capital Expenditures				$ 164.8	$ 231.5	$ 340.5	$ 305.5
Net distributions from (to) related party							(89.6)
Gross Profit				197.2	191.4	381.8	328.9
Cash Provided by (Used in) Financing Activities, Discontinued Operations						391.6	276.1
Due from Affiliate, Current				112.2		112.2		$ 121.6
Due to Related Parties, Current				21.6		21.6		$ 3.0
Affiliate general and administrative expense				28.1	26.6	70.8	42.5
Allocated Share-based Compensation Expense				$ 7.7	$ 5.8	$ 21.5	9.8
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			1,000,000.0					115,495,669
Devon Energy Corporation
Related Party Transaction [Line Items]
Allocated Share-based Compensation Expense							2.8
Pension and Other Postretirement Benefit Expense							$ 1.6
Devon Energy Corporation | Sales Revenue [Member]
Related Party Transaction [Line Items]
Concentration Risk, Percentage				14.20%	18.70%	15.70%	40.30%
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Operating Expenses				$ 0.2	$ 0.0	$ 0.2	$ 5.9
Affiliate general and administrative expense				$ 0.1	1.1	0.1	9.6
Transmission Service Agreement [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Other Income						0.2
Affiliate general and administrative expense					$ 1.1	$ 0.1	1.3
Continuing Operations [Member] | Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party							(22.1)
Continuing Operations [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues							(436.4)
Operating Expenses							340.0
Net Related Party transactions							(96.4)
Capital Expenditures							21.3
Other Expenses							53.0
Total Third-Party Transactions							74.3
Net distributions from (to) related party, non-cash							(23.2)
Net distributions from (to) related party							(45.3)
Discontinued Operations [Member]
Related Party Transaction [Line Items]
Net distributions from (to) related party							(4.4)
Discontinued Operations [Member] | Devon Energy Corporation
Related Party Transaction [Line Items]
Net distributions from (to) related party, non-cash							(39.9)
Discontinued Operations [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues							(10.4)
Operating Expenses							5.0
Net Related Party transactions							(5.4)
Capital Expenditures							0.6
Other Expenses							0.4
Total Third-Party Transactions							1.0
Net distributions from (to) related party							$ (44.3)
Gulf Coast Fractionators [Member]
Related Party Transaction [Line Items]
Ownership Percentage				38.75%		38.75%
E2 [Member]
Related Party Transaction [Line Items]
Consideration Transferred			$ 194.0
Payments to Acquire Businesses, Gross			$ 163.0
Midstream Holdings [Member] | Acacia [Member] | EMH Drop Down [Member] | EnLink Midstream LP [Member] | EnLink Midstream Holdings, LP [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 900.0	$ 925.0
Midstream Holdings [Member] | EnLink Midstream LP [Member] | EMH Drop Down [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Ownership Interest Transferred	100.00%
Class D Common Unit [Member] | Midstream Holdings [Member] | Acacia [Member] | EMH Drop Down [Member] | EnLink Midstream LP [Member] | EnLink Midstream Holdings, LP [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction, Shares		31,618,311
Class E Common Unit [Member] | Midstream Holdings [Member] | Acacia [Member] | EMH Drop Down [Member] | EnLink Midstream LP [Member] | EnLink Midstream Holdings, LP [Member] | Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction, Shares	36,629,888

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Fair Value Measurements

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

(14)  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 establishes 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 liabilities measured at fair value on a recurring basis are summarized below (in millions):

	June 30, 2015 Level 2		December 31, 2014 Level 2
Commodity Swaps*	$	14.6	$	21.7
Total	$	14.6	$	21.7

__________________________________________________

* 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):

	June 30, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	2,827.2	$	2,757.1	$	2,022.5	$	2,026.1
Obligations under capital leases	$	18.7	$	18.0	$	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 $150.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of June 30, 2015 and December 31, 2014, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2015, the Partnership had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. As of December 31, 2014, the Partnership had total borrowings of $1.8 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes as of June 30, 2015 and 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.

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Basis of Accounting, Policy

(a) Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) 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. 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 the Company, as well as the Company'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.

On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to "Devon investment interest in net income" on the Company's Condensed Consolidated Statements of Operations.

Revenue Recognition, Policy [Policy Text Block]

(b) Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services through various contractual arrangements which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal, or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the consolidated statements of operations as follows:

• Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above.

• Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Redeemable Noncontrolling Interest

(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Condensed Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holders' share of net income or loss and distributions).

New Accounting Pronouncements, Policy

(d) Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the six months ended June 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

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Goodwill and Intangible Assets (Intangible Asset by Major Class) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 906.8		$ 906.8		$ 569.5
Finite-Lived Intangible Assets, Accumulated Amortization	(66.3)		(66.3)		(36.5)
Finite-Lived Intangible Assets, Net	840.5		$ 840.5		$ 533.0
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life			11 years 2 months
Amortization of Intangible Assets	$ 18.2	$ 11.3	$ 29.7	$ 13.0

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2015

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following schedule summarizes the Partnership's non-cash financing activities for the period presented.

	Six Months Ended   June 30,
	2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	180.0
Non-cash issuance of Class C Common Units (1)	$	180.0

(1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.

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Condensed Consolidated Statements of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Affiliate purchased gas, NGLs, condensate and crude	$ 968.2	$ 661.9	$ 1,625.6	$ 1,200.8
Affiliate general and administrative expense	28.1	26.6	70.8	42.5
Affiliated Entity [Member]
Affiliate purchased gas, NGLs, condensate and crude	32.0	0.0	39.9	325.8
Affiliate operating expenses	0.2	0.0	0.2	5.9
Affiliate general and administrative expense	$ 0.1	$ 1.1	$ 0.1	$ 9.6

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Acquisition

6 Months Ended

Jun. 30, 2015

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]

Acquisition

(3) Acquisitions

Chevron Acquisition

Effective November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the equity interests (all of which were voting) in certain entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Property, plant and equipment	$	225.3
Intangibles	13.0
Liabilities assumed:
Current liabilities	(6.8		)
Total identifiable net assets	$	231.5

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 20 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. The Partnership incurred $0.4 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 1, 2015 to June 30, 2015, the Partnership recognized $16.0 million of revenues and $0.1 million of net income related to the assets acquired.

LPC Acquisition

On January 31, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million ($78.9 million, net of cash acquired). The transaction was accounted for using the acquisition method.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $21.1 million in cash)	$	107.4
Property, plant and equipment	29.8
Intangibles	43.2
Goodwill	29.6
Liabilities assumed:
Current liabilities	(106.0		)
Deferred tax liability	(4.0		)
Total identifiable net assets	$	100.0

The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Crude and Condensate segment and is non-deductible for tax purposes.

The Partnership incurred $0.2 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 31, 2015 to June 30, 2015, the Partnership recognized $559.6 million of revenues and $1.6 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $602.1 million. The purchase price consisted of $242.1 million in cash ($232.5 million, net of cash acquired), 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $9.6 million in cash)	$	26.2
Property, plant and equipment	302.1
Intangibles	281.0
Goodwill	16.9
Liabilities assumed:
Current liabilities	(24.1		)
Total identifiable net assets	$	602.1

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment and is non-deductible for tax purposes.

The Partnership incurred $3.0 million of direct transaction costs for the six months ended June 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from March 17, 2015 to June 30, 2015, the Partnership recognized $61.5 million of revenues and $4.1 million of net loss related to the assets acquired.

VEX Pipeline Drop Down

On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford shale in south Texas, together with 100% of the equity interests (all of which were voting) in certain entities, from Devon in a drop down transaction (the "VEX Drop Down"). The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX Interests were recorded on the Partnership's books at historical cost on the date of transfer of $132.7 million. The difference between the historical cost of the net assets and consideration given was $38.3 million and is recognized as a distribution to Devon. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon.

The following tables present the impact of the VEX Drop Down as presented in the Company's historical Condensed Consolidated Statements of Operations for the six months ended June 30, 2015 and three and six months ended June 30, 2014:

	Six Months Ended June 30, 2015
	Company Historical		VEX		Combined
	(in millions)
Revenues	$	2,210.8	$	4.2	$	2,215.0
Net income (loss)	$	67.2	$	2.4	$	69.6
Net income attributable to non-controlling interest	$	36.4	$	—	$	36.4
Net income attributable to EnLink Midstream, LLC	$	30.8	$	2.4	$	33.2
EnLink Midstream, LLC interest in net income	$	30.8	$	—	$	30.8

	Three Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	927.2	$	—		$	927.2
Net income (loss)	$	64.5	$	(2.1	)	$	62.4
Net income attributable to non-controlling interest	$	35.7	$	—		$	35.7
Net income attributable to EnLink Midstream, LLC	$	28.8	$	(2.1	)	$	26.7
EnLink Midstream, LLC interest in net income	$	28.8	$	—		$	28.8

	Six Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	1,650.3	$	—		$	1,650.3
Net income (loss)	$	113.9	$	(3.0	)	$	110.9
Net income attributable to non-controlling interest	$	42.8	$	—		$	42.8
Net income attributable to EnLink Midstream, LLC	$	71.1	$	(3.0	)	$	68.1
EnLink Midstream, LLC interest in net income (1)	$	35.6	$	—		$	35.6

(1) Represents net income for the period from March 7, 2014 through June 30, 2014.

Devon Merger

On March 7, 2014, EMI merged with and into a wholly-owned subsidiary of the Company, and 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 Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. As of June 30, 2015, the Company, through its ownership of EMI, owned approximately 5.3% of the outstanding limited partner interests in the Partnership and owned 100.0% of the General Partner. The Company, through its ownership of 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 was 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.

For the period from March 7, 2014 to June 30, 2014, the Company recognized $968.8 million of revenues and $26.5 million of net loss related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, and VEX Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Pro forma financial information associated with the business combination and acquisitions is reflected below.

		Three Months Ended June 30,		Six Months Ended   June 30,
		2014		2015		2014
	(in millions)
Pro forma total revenues (1)		$	1,453.4	$	2,337.2	$	2,834.6
Pro forma net income		$	55.2	$	64.7	$	74.0
Pro forma net income attributable to EnLink Midstream, LLC		$	25.3	$	31.0	$	42.7
Pro forma net income per common unit:
Basic		$	0.17	$	0.18	$	0.28
Diluted		$	0.17	$	0.18	$	0.28

(1) On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

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Earnings per Unit and Dilution Computations (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Capital Unit [Line Items]
Distribution paid (usd per unit)	$ 0.25	$ 0.245	$ 0.22	$ 0.18
Enlink Midstream, LLC interest in net income	$ 14.5		$ 28.8		$ 30.8	$ 35.6
Distributed Earnings	41.4		36.2		81.8	50.9
Undistributed Earnings, Basic	$ (26.9)		$ (7.4)		$ (51.0)	$ (15.3)
Basic common unit (usd per unit)	$ 0.09		$ 0.18		$ 0.19	$ 0.22
Diluted common unit (usd per unit)	$ 0.09		$ 0.18		$ 0.19	$ 0.22
Common Unit
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income	$ 14.4		$ 28.7		$ 30.6	$ 35.4
Distributed Earnings	41.1		36.1		81.3	50.6
Undistributed Earnings, Basic	(26.7)		(7.4)		(50.7)	(15.2)
Restricted Stock Units (RSUs)
Capital Unit [Line Items]
Enlink Midstream, LLC interest in net income	0.1		0.1		0.2	0.2
Distributed Earnings	0.3		0.1		0.5	0.3
Undistributed Earnings, Basic	$ (0.2)		$ 0.0		$ (0.3)	$ (0.1)
Capital Unit, Class B [Member]
Capital Unit [Line Items]
Distribution paid (usd per unit)						$ 0.05

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Derivatives (Derivatives Outstanding) (Details) gal in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2015 USD ($) MMBTU gal	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Net fair value of derivatives	$ 14.6	$ 21.7
Not Designated as Hedging Instrument
Derivative [Line Items]
Net fair value of derivatives	$ 14.6
Liquids | Short Contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	60.5
Net fair value of derivatives	$ 18.1
Liquids | Long Contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	35.8
Net fair value of derivatives	$ (2.6)
Gas | Short Contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	3.7
Net fair value of derivatives	$ 2.6
Gas | Long Contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	2.7
Net fair value of derivatives	$ (3.5)

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Acquisition (Table)

6 Months Ended

Jun. 30, 2015

Jun. 30, 2014

Business Acquisition [Line Items]

ScheduleOfPriorPeriodAdjustmentsRelatedToAssetDropDown [Table Text Block]

	Six Months Ended June 30, 2015
	Company Historical		VEX		Combined
	(in millions)
Revenues	$	2,210.8	$	4.2	$	2,215.0
Net income (loss)	$	67.2	$	2.4	$	69.6
Net income attributable to non-controlling interest	$	36.4	$	—	$	36.4
Net income attributable to EnLink Midstream, LLC	$	30.8	$	2.4	$	33.2
EnLink Midstream, LLC interest in net income	$	30.8	$	—	$	30.8

	Six Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	1,650.3	$	—		$	1,650.3
Net income (loss)	$	113.9	$	(3.0	)	$	110.9
Net income attributable to non-controlling interest	$	42.8	$	—		$	42.8
Net income attributable to EnLink Midstream, LLC	$	71.1	$	(3.0	)	$	68.1
EnLink Midstream, LLC interest in net income (1)	$	35.6	$	—		$	35.6

(1) Represents net income for the period from March 7, 2014 through June 30, 2014.

	Three Months Ended June 30, 2014
	Company Historical		VEX			Combined
	(in millions)
Revenues	$	927.2	$	—		$	927.2
Net income (loss)	$	64.5	$	(2.1	)	$	62.4
Net income attributable to non-controlling interest	$	35.7	$	—		$	35.7
Net income attributable to EnLink Midstream, LLC	$	28.8	$	(2.1	)	$	26.7
EnLink Midstream, LLC interest in net income	$	28.8	$	—		$	28.8

Business Acquisition, Pro Forma Information

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, and VEX Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Pro forma financial information associated with the business combination and acquisitions is reflected below.

		Three Months Ended June 30,		Six Months Ended   June 30,
		2014		2015		2014
	(in millions)
Pro forma total revenues (1)		$	1,453.4	$	2,337.2	$	2,834.6
Pro forma net income		$	55.2	$	64.7	$	74.0
Pro forma net income attributable to EnLink Midstream, LLC		$	25.3	$	31.0	$	42.7
Pro forma net income per common unit:
Basic		$	0.17	$	0.18	$	0.28
Diluted		$	0.17	$	0.18	$	0.28

(1) On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

Chevron Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Property, plant and equipment	$	225.3
Intangibles	13.0
Liabilities assumed:
Current liabilities	(6.8		)
Total identifiable net assets	$	231.5

LPC [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $21.1 million in cash)	$	107.4
Property, plant and equipment	29.8
Intangibles	43.2
Goodwill	29.6
Liabilities assumed:
Current liabilities	(106.0		)
Deferred tax liability	(4.0		)
Total identifiable net assets	$	100.0

Coronado [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.

Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $9.6 million in cash)	$	26.2
Property, plant and equipment	302.1
Intangibles	281.0
Goodwill	16.9
Liabilities assumed:
Current liabilities	(24.1		)
Total identifiable net assets	$	602.1

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Fair Value Measurement (Details Textuals) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	May. 12, 2015
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 150.0
Long-term Debt	2,827.2	$ 2,022.5
Unsecured Debt	$ 2,676.9	$ 1,785.1
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	2.70%	2.70%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	7.10%	7.10%
Partnership [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 150.0	$ 237.0
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior Notes	$ 399.6	$ 399.5
Debt Instrument, Interest Rate, Stated Percentage	2.70%	2.70%
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes	$ 553.0	$ 553.2
Debt Instrument, Interest Rate, Stated Percentage	4.40%	4.40%
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior Notes	$ 349.7	$ 349.7
Debt Instrument, Interest Rate, Stated Percentage	5.60%	5.60%
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior Notes	$ 443.0	$ 298.3
Debt Instrument, Interest Rate, Stated Percentage	5.05%	5.05%	5.05%
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes	$ 182.9	$ 184.4
Debt Instrument, Interest Rate, Stated Percentage	7.125%	7.125%

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Derivative Instrument

Net liabilities measured at fair value on a recurring basis are summarized below (in millions):

	June 30, 2015 Level 2		December 31, 2014 Level 2
Commodity Swaps*	$	14.6	$	21.7
Total	$	14.6	$	21.7

__________________________________________________

* The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

Fair Value Financial Instrument

Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):

	June 30, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	2,827.2	$	2,757.1	$	2,022.5	$	2,026.1
Obligations under capital leases	$	18.7	$	18.0	$	20.3	$	19.8

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Derivatives

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(13)Derivatives

Interest Rate Swaps

The Partnership entered into interest rate swaps in April and May 2015 in connection with the issuance of the 2025 Notes in May 2015.                

The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2015		2015
Settlement gains on derivatives	$	3.6	$	3.6

Commodity Swaps

The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the fair value of the Partnership's derivatives are recorded in revenue in the period incurred. In addition, the Partnership's risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where the Partnership receives a percentage of liquids as a fee for processing third-party gas or where the Partnership receives a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of its business and (3) where the Partnership is mitigating the price risk for product held in inventory or storage.

The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014*
Change in fair value of derivatives	$	(2.5	)	$	(1.3	)	$	(6.3	)	$	(2.0	)
Realized gain (loss) on derivatives	3.7			(0.3		)	7.7			(0.9		)
Gain (loss) on derivative activity	$	1.2		$	(1.6	)	$	1.4		$	(2.9	)

* The six months ended June 30, 2014 amounts consist only of the period from March 7, 2014 through June 30, 2014. 

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):

	June 30, 2015			December 31, 2014
Fair value of derivative assets — current	$	14.0		$	16.7
Fair value of derivative assets — long term	4.9			10.0
Fair value of derivative liabilities — current	(3.5		)	(3.0		)
Fair value of derivative liabilities — long term	(0.8		)	(2.0		)
Net fair value of derivatives	$	14.6		$	21.7

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at June 30, 2015. The remaining term of the contracts extend no later than December 2016.

			June 30, 2015
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(60.5	)	$	18.1
NGL (long contracts)	Swaps	Gallons	35.8		(2.6		)
Natural Gas (short contracts)	Swaps	MMBtu	(3.7	)	2.6
Natural Gas (long contracts)	Swaps	MMBtu	2.7		(3.5		)
Total fair value of derivatives					$	14.6

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 June 30, 2015 of $18.9 million would be reduced to $14.6 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 Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):

	Maturity Periods
	Less than one year		One to two years		More than two years		Total fair value
June 30, 2015	$	10.5	$	4.1	$	—	$	14.6