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, 2016

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 22, 2016, the Registrant had 180,035,410 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	31
3.	Quantitative and Qualitative Disclosures About Market Risk	51
4.	Controls and Procedures	53
	PART II—OTHER INFORMATION
1.	Legal Proceedings	55
1A.	Risk Factors	55
6.	Exhibits	56

2

ENLINK MIDSTREAM, LLC

Condensed Consolidated Balance Sheets

	June 30, 2016		December 31, 2015
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	10.2	$	18.0
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	68.5		37.5
Accrued revenue and other	295.7		268.8
Related party	72.6		110.8
Fair value of derivative assets	5.3		16.8
Natural gas and NGLs inventory, prepaid expenses and other	39.6		41.8
Total current assets	491.9		493.7
Property and equipment, net of accumulated depreciation of $1,941.4 and $1,757.6, respectively	6,160.4		5,666.8
Intangible assets, net of accumulated amortization of $112.1 and $54.6, respectively	1,666.7		689.9
Goodwill	1,541.3		2,413.9
Investment in unconsolidated affiliates	299.7		274.3
Other assets, net	2.3		2.7
Total assets	$	10,162.3	$	9,541.3
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	46.0	$	33.2
Accounts payable to related party	10.4		14.8
Accrued gas, NGLs, condensate and crude oil purchases	247.3		206.7
Fair value of derivative liabilities	5.8		2.9
Installment payable, net of discount of $14.2	235.8		—
Other current liabilities	146.1		174.8
Total current liabilities	691.4		432.4
Long-term debt	3,364.1		3,066.0
Fair value of derivative liabilities	—		0.1
Asset retirement obligation	13.2		12.9
Other long-term liabilities	57.0		65.9
Installment payable, net of discount of $39.3	210.7		—
Deferred tax liability	539.1		532.1
Redeemable non-controlling interest	6.5		7.0
Members’ equity:
Members' equity (180,035,410 and 164,242,160 units issued and outstanding at June 30, 2016 and December 31, 2015, respectively)	1,970.2		2,285.7
Non-controlling interest	3,310.1		3,139.2
Total members' equity	5,280.3		5,424.9
Commitment and Contingencies (Note 15)
Total liabilities and members’ equity	$	10,162.3	$	9,541.3

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,
	2016			2015			2016			2015
	(Unaudited) (In millions, except per unit amounts)
Revenues:
Product sales	$	738.3		$	956.2		$	1,326.8		$	1,626.9
Product sales - affiliates	31.7			31.7			56.2			47.9
Midstream services	108.3			135.9			222.8			238.3
Midstream services - affiliates	160.6			149.5			323.2			300.5
Gain (loss) on derivative activity	(5.7		)	1.2			(6.1		)	1.4
Total revenues	1,033.2			1,274.5			1,922.9			2,215.0
Operating costs and expenses:
Cost of sales (1)	732.4			968.2			1,318.6			1,625.6
Operating expenses (2)	100.1			109.1			198.3			207.6
General and administrative (3)	30.3			28.1			65.4			70.8
Loss on disposition of assets	0.3			—			0.1			—
Depreciation and amortization	124.9			97.7			246.8			189.0
Impairments	—			—			873.3			—
Total operating costs and expenses	988.0			1,203.1			2,702.5			2,093.0
Operating income (loss)	45.2			71.4			(779.6		)	122.0
Other income (expense):
Interest expense, net of interest income	(46.5		)	(22.6		)	(90.5		)	(41.7		)
Income (loss) from unconsolidated affiliates	0.8			5.9			(1.6		)	9.7
Other income (loss)	(0.1		)	0.1			—			0.5
Total other expense	(45.8		)	(16.6		)	(92.1		)	(31.5		)
Income (loss) before non-controlling interest and income taxes	(0.6		)	54.8			(871.7		)	90.5
Income tax benefit (provision)	1.8			(10.2		)	1.6			(20.9		)
Net income (loss)	1.2			44.6			(870.1		)	69.6
Net income (loss) attributable to the non-controlling interest	0.4			28.4			(413.3		)	36.4
Net income (loss) attributable to EnLink Midstream, LLC	$	0.8		$	16.2		$	(456.8	)	$	33.2
Devon investment interest in net income	$	—		$	1.7		$	—		$	2.4
EnLink Midstream, LLC interest in net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit	$	0.01		$	0.09		$	(2.55	)	$	0.19
Diluted common unit	$	0.01		$	0.09		$	(2.55	)	$	0.19

(1) Includes $49.8 million and $32.0 million for the three months ended June 30, 2016 and 2015, respectively, and $92.4 millionand $39.9 millionfor the six months ended June 30, 2016 and 2015, respectively, of affiliate cost of sales.

(2) Includes $0.2 million and $0.2 million for the three months ended June 30, 2016 and 2015, respectively, and $0.3 million and $0.2 million for the six months ended June 30, 2016 and 2015, respectively, of affiliate operating expenses.

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

See accompanying notes to condensed consolidated financial statements.

4

ENLINK MIDSTREAM, LLC

Consolidated Statement of Changes in Members’ Equity

Six Months Ended June 30, 2016

	Common Units				Non-Controlling Interest						Redeemable Non-controlling Interest (Temporary Equity)
	$			Units	$			Total			$
	(Unaudited)
	(In millions)
Balance, December 31, 2015	$	2,285.7		164.2	$	3,139.2		$	5,424.9		$	7.0
Unit-based compensation	7.7			—	7.7			15.4			—
Issuance of common units by the Partnership	—			—	52.3			52.3			—
Issuance of Preferred Units by the Partnership	—			—	724.1			724.1			—
Issuance of common units	214.9			15.6	—			214.9			—
Conversion of restricted units for common, net of units withheld for taxes	(1.1		)	0.2	—			(1.1		)	—
Non-controlling partner's impact of conversion of restricted units	—			—	(1.1		)	(1.1		)	—
Change in equity due to issuance of units by the Partnership	12.5			—	(20.0		)	(7.5		)	—
Non-controlling interest distributions	—			—	(186.1		)	(186.1		)	—
Non-controlling interest contribution	—			—	5.9			5.9			—
Distributions to members	(92.7		)	—	—			(92.7		)	—
Distributions to redeemable non-controlling interest	—			—	—			—			(0.5		)
Contributions from Devon to the Partnership	—			—	1.4			1.4			—
Net loss	(456.8		)	—	(413.3		)	(870.1		)	—
Balance, June 30, 2016	$	1,970.2		180.0	$	3,310.1		$	5,280.3		$	6.5

See accompanying notes to condensed consolidated financial statements.

5

ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows

	Six Months Ended June 30,
	2016			2015
	(Unaudited) (In millions)
Cash flows from operating activities:
Net income (loss)	$	(870.1	)	$	69.6
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	873.3			—
Depreciation and amortization	246.8			189.0
Accretion expense	0.2			0.3
Loss on disposition of assets	0.1			—
Deferred tax (benefit) expense	(0.6		)	17.8
Non-cash unit-based compensation	15.4			21.5
(Gain) loss on derivatives recognized in net income (loss)	6.1			(5.0		)
Cash settlements on derivatives	8.3			11.3
Amortization of debt issue costs	1.9			1.5
Amortization of net (premium) discount on notes	24.3			(1.5		)
Redeemable non-controlling interest expense	0.3			(3.3		)
Distribution of earnings from unconsolidated affiliates	—			10.3
(Income) loss from unconsolidated affiliates	1.6			(9.7		)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other	(18.4		)	57.3
Natural gas and NGLs inventory, prepaid expenses and other	12.1			(26.6		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	2.9			(55.5		)
Net cash provided by operating activities	304.2			277.0
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(288.2		)	(349.2		)
Acquisition of business, net of cash acquired	(791.3		)	(324.8		)
Proceeds from sale of property	0.8			0.1
Investment in unconsolidated affiliates	(41.8		)	—
Distribution from unconsolidated affiliates in excess of earnings	14.8			8.9
Net cash used in investing activities	(1,105.7		)	(665.0		)
Cash flows from financing activities:
Proceeds from borrowings	847.1			2,327.4
Payments on borrowings	(549.1		)	(1,521.2		)
Payments on capital lease obligations	(2.1		)	(1.6		)
Decrease in drafts payable	—			(12.4		)
Debt financing costs	(0.4		)	(9.5		)
Mandatorily redeemable non-controlling interest	(4.0		)	—
Conversion of restricted units, net of units withheld for taxes	(1.1		)	(2.8		)
Conversion of Partnership's restricted units, net of units withheld for taxes	(1.1		)	(2.5		)
Proceeds from issuance of Partnership's common units	52.3			4.1
Distributions to non-controlling partners	(186.6		)	(175.7		)
Distribution to Members	(92.7		)	(79.3		)
Contributions from Devon	1.4			28.8
Distributions to Devon for net assets acquired	—			(171.0		)
Proceeds from issuance of Partnership Preferred Units	724.1			—
Contributions by non-controlling interest	5.9			7.3
Net cash provided by financing activities	793.7			391.6
Net increase (decrease) in cash and cash equivalents	(7.8		)	3.6
Cash and cash equivalents, beginning of period	18.0			68.4
Cash and cash equivalents, end of period	$	10.2		$	72.0
Cash paid for interest	$	67.8		$	44.4
Cash paid (refund) for income taxes	$	(5.8	)	$	13.4

See accompanying notes to condensed consolidated financial statements.

6

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements

June 30, 2016

(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 EnLink Oklahoma Gas Processing, LP (formerly known as EnLink TOM Holdings, LP) and its consolidated subsidiaries (collectively, “EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.

(a)Organization of Business

EnLink Midstream, LLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

Our assets consist of equity interests in the Partnership and EnLink Oklahoma T.O. 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. EnLink Oklahoma T.O. is a partnership held by us and the Partnership and is engaged in the gathering and processing of natural gas. As of June 30, 2016, our interests in the Partnership and EnLink Oklahoma T.O. consist of the following:

• 88,528,451 common units representing an aggregate 23.0% limited partner interest in the Partnership;

• 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

• 16% limited partner interest in EnLink Oklahoma T.O.

(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. The Partnership connects the wells of producers in its market areas to its gathering systems, processes natural gas to remove NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Partnership provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership also has crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. The Partnership's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to its fractionators in south Louisiana. The Partnership's crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. The Partnership's processing plants remove NGLs and 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.

(c) Consolidation of the Partnership

In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU 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.  Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC, including the consideration of the Incentive Distribution Rights, is considered the primary beneficiary as it has the power to

7

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership.

(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.

During the first half of 2015, the Partnership acquired assets from Devon through drop down transactions. Due to our control of the Partnership through our ownership and control of the General Partner and Devon's control of us through its ownership of our managing member, 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 condensed 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) Recent Accounting Pronouncements

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which will update ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2016-12 has the same effective date and transition requirements as ASU 2014-09, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our condensed consolidated financial statements and related disclosures.

8

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

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 Partnership'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.

(3) Acquisitions

Matador Acquisition

On October 1, 2015, the Partnership acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million. The transaction was accounted for using the acquisition method.

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

Purchase Price Allocation (in millions):
Assets acquired:
Current assets	$	1.1
Property, plant and equipment	35.5
Intangibles	98.8
Goodwill	9.8
Liabilities assumed:
Current liabilities	(3.9		)
Total identifiable net assets	$	141.3

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership's Texas segment and is non-deductible for tax purposes.

Deadwood Acquisition

Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, the Partnership acquired Apache's 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property, plant and equipment. The final working capital settlement paid to Apache was approximately $1.5 million. The transaction was accounted for using the acquisition method.

9

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Tall Oak Acquisition

On January 7, 2016, we and the Partnership acquired a 16% and 84% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by the Partnership no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The Partnership's installment payables are valued net of discount within the total purchase price.

The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $784.2 million in cash paid by the Partnership, the majority of which was derived from the proceeds from the issuance of Preferred Units, and (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by us and approximately $22.2 million in cash paid by us. The transaction was accounted for using the acquisition method.

The following table presents the consideration we paid and 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.

Consideration (in millions):
Cash	$	806.4
Issuance of common units	214.9
The Partnership's total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018	420.9
Total consideration	$	1,442.2
Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $12.8 million in cash)	$	23.0
Property, plant and equipment	423.2
Intangibles	1,034.3
Liabilities assumed:
Current liabilities	(38.3		)
Total identifiable net assets	$	1,442.2

The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years.

We incurred $3.7 million of direct transaction costs for the six months ended June 30, 2016. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 7, 2016 to June 30, 2016, we recognized $72.2 million of revenues and $23.5 million of net loss related to the assets acquired.

10

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. 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 acquisitions is reflected below.

	Three Months Ended    June 30,		Six Months Ended   June 30,
	2015		2015
	(in millions)
Pro forma total revenues	$	1,283.3	$	2,350.9
Pro forma net income	$	27.7	$	31.5
Pro forma net income attributable to EnLink Midstream, LLC	$	12.2	$	22.8
Pro forma net income per common unit:
Basic	$	0.07	$	0.13
Diluted	$	0.07	$	0.13

(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. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During February 2016, we determined that continued further weakness in the overall energy sector driven by low commodity prices together with a further decline in our unit price and the Partnership's unit price subsequent to year-end caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units.

We and the Partnership perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments for the Texas and Crude and Condensate reporting units. We use a market approach to perform the assessment for our Corporate reporting unit. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, control premium and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors.

The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. Using the fair value approaches described above, in step one of the goodwill impairment test, we and the Partnership determined that the estimated fair values of the Partnership's Texas and Crude and Condensate reporting units and our Corporate reporting unit were less than their respective carrying amounts. At the Partnership's Texas and Crude and Condensate reporting units, this is primarily related to increases in the discount rate subsequent to year-end. For our Corporate reporting unit, this is primarily due to a further decline in our unit price subsequent to year-end. The second step of the goodwill impairment test at the Partnership measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized for the three months ended March 31, 2016, which is included in the six months ended June 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.

11

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

We and the Partnership concluded that the fair value of goodwill of the Oklahoma reporting unit exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with this remaining reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

Our and the Partnership's respective impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our and the Partnership's assumptions and estimates, or assumptions and estimates change due to new information, we and the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The estimated fair values of our Corporate reporting unit and the Partnership's Texas reporting unit may be impacted in the future by a further decline in our unit price or the Partnership's unit price or a continuing prolonged period of lower commodity prices which may adversely affect the Partnership's estimate of future cash flows all of which could result in future goodwill impairment charges.

The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):

	Texas			Louisiana		Oklahoma		Crude and Condensate			Corporate			Totals
Six Months Ended June 30, 2016
Balance, beginning of period	$	703.5		$	—	$	190.3	$	93.2		$	1,426.9		$	2,413.9
Impairment	(473.1		)	—		—		(93.2		)	(307.0		)	(873.3		)
Acquisition adjustment	0.7			—		—		—			—			0.7
Balance, end of period	$	231.1		$	—	$	190.3	$	—		$	1,119.9		$	1,541.3

Intangible Assets

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

The following table represents the Partnership's change in carrying value of intangible assets (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Six Months Ended June 30, 2016
Customer relationships, beginning of period	$	744.5	$	(54.6	)	$	689.9
Acquisitions	1,034.3		—			1,034.3
Amortization expense	—		(57.5		)	(57.5		)
Customer relationships, end of period	$	1,778.8	$	(112.1	)	$	1,666.7

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $30.0 million and $18.2 million for the three months ended June 30, 2016 and 2015, respectively, and $57.5 million and $29.7 million for the six months ended June 30, 2016 and 2015, respectively.

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

2016 (remaining)	$	58.4
2017	116.7
2018	116.7
2019	116.7
2020	116.7
Thereafter	1,141.5
Total	$	1,666.7

12

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and six months ended June 30, 2016 and 2015, Devon was a significant customer to the Partnership. Devon accounted for 18.6% and 19.7% of the Partnership's revenues for the three and six months ended June 30, 2016, respectively, and 14.2% and 15.7% for the three and six months ended June 30, 2015, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $72.6 million as of June 30, 2016 and $110.8 million as of December 31, 2015. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $10.4 million as of June 30, 2016 and $14.8 million as of December 31, 2015. 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.

EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

In January 2016, in connection with the Tall Oak acquisition, we acquired a Gas Gathering and Processing Agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has a minimum volume commitment that will remain in place during each calendar quarter for the next five years and a remaining overall term of approximately 13 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC 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 DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. EnLink Oklahoma T.O. will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

(6) Long-Term Debt

As of June 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):

	June 30, 2016			December 31, 2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively	$	697.0		$	414.0
Company credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at June 30, 2016 was 4.25%	15.1			—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.3 million at June 30, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%	399.7			399.6
The Partnership's senior unsecured notes (due 2022), including a premium of $17.5 million at June 30, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%	180.0			181.4
The Partnership's senior unsecured notes (due 2024), net of premium of $2.7 million at June 30, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%	552.7			552.9
The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at June 30, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%	748.8			748.8
The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at June 30, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%	349.8			349.8
The Partnership's senior unsecured notes (due 2045), net of discount of $6.8 million at June 30, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%	443.2			443.1
Debt issuance cost, net of amortization of $7.0 million at June 30, 2016 and $5.1 million at December 31, 2015.	(22.2		)	(23.8		)
Other debt	—			0.2
Debt classified as long-term	$	3,364.1		$	3,066.0

13

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Company Credit Facility

The Company has 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) 88,528,451 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (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 0.5%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing the credit facility could be foreclosed upon.

As of June 30, 2016 there was $15.1 million in outstanding borrowings under the credit facility, leaving approximately $234.9 million available for future borrowing based on the borrowing capacity of $250.0 million. The Company expect to be in compliance with all credit facility covenants for at least the next twelve months.

Partnership Credit Facility

The Partnership has a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”) that matures on March 6, 2020. Under the Partnership credit facility, 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 $500.0 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year on each occasion. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the 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, 2016, there were $11.1 million in outstanding letters of credit and $697.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $791.9 million available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms and conditions 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, 2015. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

14

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(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,
	2016			2015		2016			2015
	(in millions)
ENLC income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income before income taxes:

	Three Months Ended    June 30,					Six Months Ended   June 30,
	2016			2015		2016			2015
	(in millions)
Tax expense (benefit) at statutory federal rate (35%)	$	0.5		$	8.4	$	(160.0	)	$	17.4
State income taxes expense (benefit), net of federal tax benefit	—			0.6		(14.9		)	1.2
Income tax expense (benefit) from partnership	(2.3		)	0.7		(1.3		)	1.9
Non-deductible expense related to asset impairment	—			—		173.9			—
Other	—			0.5		0.7			0.4
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

(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, 2016, the Partnership sold an aggregate of 3.3 million common units under the BMO EDA, generating proceeds of approximately $52.3 million (net of approximately $0.5 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2016, approximately $264.4 million remains available to be issued under the BMO EDA.

(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. The Class C Common Units were substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units converted into common units on a one-for-one basis on May 13, 2016.

15

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(c) Preferred Units

In January 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (“Preferred Units”) representing the Partnership's limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund the Partnership's portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into the Partnership's common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership's option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the General Partner or our managing member, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. A distribution on the Preferred Units for the three months ended March 31, 2016, was paid-in kind through the issuance of 992,445 Preferred Units on May 12, 2016. A distribution on the Preferred Units was declared for the three months ended June 30, 2016, which will result in the issuance of 1,083,589 additional Preferred Units on August 11, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the three and six months ended June 30, 2016, $18.0 million and $29.8 million of income was allocated to the Preferred Units, respectively.

(d)  Distributions

Unless restricted by the terms of the Partnership 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 Preferred 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, 2016 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2015	$	0.39	February 11, 2016
First Quarter of 2016	$	0.39	May 12, 2016
Second Quarter of 2016	$	0.39	August 11, 2016

16

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(e) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in (d) above. 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, 2016 and 2015 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Income allocation for incentive distributions	$	14.2		$	11.3		$	28.0		$	20.1
Unit-based compensation attributable to ENLC’s restricted units	(3.6		)	(3.9		)	(7.6		)	(10.9		)
General Partner share of net income (loss)	—			0.2			(2.4		)	0.3
General Partner interest in drop down transactions	—			11.5			—			36.1
General Partner interest in net income	$	10.6		$	19.1		$	18.0		$	45.6

(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 (loss) attributable to the drop down interests acquired during 2015 from Devon for periods prior to acquisition is not allocated for purposes of calculating net income (loss) per common unit as they were fully assigned to the general partner interest. The following table reflects the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2016 and 2015 (in millions, except per unit amounts):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
EnLink Midstream, LLC interest in net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Distributed earnings allocated to:
Common units (1) (2)	$	45.9		$	41.1		$	91.5		$	81.3
Unvested restricted units (1) (2)	0.5			0.3			1.0			0.5
Total distributed earnings	$	46.4		$	41.4		$	92.5		$	81.8
Undistributed loss allocated to:
Common units	$	(44.7	)	$	(26.7	)	$	(543.2	)	$	(50.7	)
Unvested restricted units	(0.9		)	(0.2		)	(6.1		)	(0.3		)
Total undistributed loss	$	(45.6	)	$	(26.9	)	$	(549.3	)	$	(51.0	)
Net income (loss) allocated to:
Common units	$	1.2		$	14.4		$	(451.7	)	$	30.6
Unvested restricted units	(0.4		)	0.1			(5.1		)	0.2
Total net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Basic and diluted net income (loss) per unit:
Basic	$	0.01		$	0.09		$	(2.55	)	$	0.19
Diluted	$	0.01		$	0.09		$	(2.55	)	$	0.19

(1) Three months ended June 30, 2016 and 2015 represents a declared distribution of $0.255 per unit payable August 12, 2016 and a distribution of $0.25 per unit paid on August 14, 2015, respectively.

(2) Six months ended June 30, 2016 and 2015 represents a distribution of $0.255 per unit paid on May 13, 2016, a declared distribution of $0.255 per unit payable on August 12, 2016 and distributions of $0.245 per unit paid on May 15, 2015 and of $0.25 per unit paid on August 14, 2015.

17

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

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,
	2016	2015	2016	2015
Basic and diluted earnings per unit:
Weighted average common units outstanding	180.0	164.2	179.4	164.2
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	180.0	164.2	179.4	164.2
Dilutive effect of restricted units issued	0.8	0.4	—	0.4
Total weighted average diluted common units outstanding	180.8	164.6	179.4	164.6

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.

(10)Asset Retirement Obligations

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

	Six Months Ended   June 30,
	2016			2015
	(in millions)
Beginning asset retirement obligations	$	14.0		$	20.6
Revisions to existing liabilities	(0.4		)	(4.0		)
Accretion	0.2			0.3
Liabilities settled	(0.6		)	(3.2		)
Ending asset retirement obligations	$	13.2		$	13.7

There are no asset retirement obligations included in Other Current Liabilities as of June 30, 2016. Asset retirement obligations of $1.1 million are included in Other Current Liabilities as of December 31, 2015.

18

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(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 Gulf Coast Fractionators (“GCF”) at June 30, 2016 and 2015 and approximately 31.0% ownership interest in Howard Energy Partners (“HEP”) at June 30, 2016 and 2015.

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, 2016
Contributions	$	—		$	34.7		$	34.7
Distributions	$	0.5		$	5.1		$	5.6
Equity in net income	$	0.5		$	0.3		$	0.8
June 30, 2015
Distributions	$	4.2		$	8.2		$	12.4
Equity in net income	$	2.9		$	3.0		$	5.9
Six months ended
June 30, 2016
Contributions	$	—		$	41.8		$	41.8
Distributions	$	3.5		$	11.3		$	14.8
Equity in net loss	$	(1.2	)	$	(0.4	)	$	(1.6	)
June 30, 2015
Distributions	$	6.9		$	12.3		$	19.2
Equity in net income	$	6.3		$	3.4		$	9.7

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

	June 30, 2016		December 31, 2015
Gulf Coast Fractionators	$	47.9	$	52.6
Howard Energy Partners	251.8		221.7
Total investment in unconsolidated affiliates	$	299.7	$	274.3

(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 condensed consolidated financial statements. On April 7, 2016, the General Partner amended and restated the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). Amendments to the GP Plan included an increase to the number of the Partnership's common units authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes.

19

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

The Partnership and we 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 is recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and EnLink Oklahoma T.O. 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,
	2016		2015		2016		2015
Cost of unit-based compensation charged to general and administrative expense	$	5.7	$	6.6	$	12.0	$	18.5
Cost of unit-based compensation charged to operating expense	1.7		1.1		3.4		3.0
Total amount charged to income	$	7.4	$	7.7	$	15.4	$	21.5
Interest of non-controlling partners in unit-based compensation	$	2.7	$	3.7	$	5.6	$	9.2
Amount of related income tax benefit recognized in income	$	1.8	$	1.5	$	3.7	$	4.6

(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, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,253,729			$	29.59
Granted	1,046,685			10.03
Vested*	(297,439		)	30.33
Forfeited	(40,998		)	22.17
Non-vested, end of period	1,961,977			$	19.20
Aggregate intrinsic value, end of period (in millions)	$	32.6

* Vested units include 85,366 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2016 and 2015, respectively, is provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	0.1	$	0.4	$	3.8	$	7.2
Fair value of units vested	$	—	$	0.5	$	9.0	$	7.5

As of June 30, 2016, there was $19.0 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 1.8 years.

(c)EnLink Midstream Partners, LP Performance Units

In 2016, the General Partner and the managing member of ENLC granted performance awards under the GP Plan and the EnLink Midstream, LLC 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

20

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership's common units and the designated peer group securities; (iii) an estimated ranking of the Partnership among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of 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:	January 2016			February 2016
Beginning TSR Price	$	14.82		$	14.82
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	39.71		%	42.33		%
Distribution yield	12.10		%	19.20		%

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

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	118,126			$	35.41
Granted	258,078			9.81
Forfeited	(2,798		)	36.18
Non-vested, end of period	373,406			$	17.71
Aggregate intrinsic value, end of period (in millions)	$	6.2

As of June 30, 2016 there was $4.4 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 2.0 years.

(d)EnLink Midstream, LLC Restricted Incentive Units

ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the six months endedJune 30, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,148,893			$	34.78
Granted	1,038,619			9.44
Vested*	(320,497		)	36.92
Forfeited	(37,952		)	23.95
Non-vested, end of period	1,829,063			$	20.24
Aggregate intrinsic value, end of period (in millions)	$	29.1

* Vested units include 91,256 units withheld for payroll taxes paid on behalf of employees.

21

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

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, 2016 and 2015, respectively, are provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	0.6	$	3.8	$	8.9
Fair value of units vested	$	—	$	0.6	$	11.8	$	9.2

As of June 30, 2016, there was $18.6 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 1.7 years.

(e) EnLink Midstream, LLC's Performance Units

In 2016, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC's common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the 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:	January 2016			February 2016
Beginning TSR Price	$	15.38		$	15.38
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	46.02		%	52.05		%
Distribution yield	8.60		%	14.00		%

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

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	105,080			$	40.50
Granted	242,646			9.59
Forfeited	(2,525		)	41.31
Non-vested, end of period	345,201			$	18.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

As of June 30, 2016, there was $4.2 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 2.0 years.  

(13)Derivatives

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

22

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

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 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Change in fair value of derivatives	$	(8.4	)	$	(2.5	)	$	(14.4	)	$	(6.3	)
Realized gain on derivatives	2.7			3.7			8.3			7.7
Gain (loss) on derivative activity	$	(5.7	)	$	1.2		$	(6.1	)	$	1.4

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

	June 30, 2016			December 31, 2015
Fair value of derivative assets — current	$	5.3		$	16.8
Fair value of derivative liabilities — current	(5.8		)	(2.9		)
Fair value of derivative liabilities — long term	—			(0.1		)
Net fair value of derivatives	$	(0.5	)	$	13.8

Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity in the Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The total estimated fair value liability of derivative contracts of $0.5 million as of June 30, 2016 has a maturity date of less than one year.

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, 2016. The remaining term of the contracts extend no later than June 2017.

			June 30, 2016
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(31.9	)	$	3.4
NGL (long contracts)	Swaps	Gallons	11.4		(0.4		)
Natural Gas (short contracts)	Swaps	MMBtu	(6.3	)	(2.9		)
Natural Gas (long contracts)	Swaps	MMBtu	1.3		(0.1		)
Condensate (short contracts)	Swaps	MMBbls	(0.1	)	(0.5		)
Total fair value of derivatives					$	(0.5	)

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

23

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, 2016 of $5.3 million would be eliminated due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. 

Interest Rate Swaps

The Partnership entered into interest rate swaps during April and May 2015 in connection with the issuance of the 2025 Notes in May 2015. The Partnership did not enter into any interest rate swaps for the six months ended June 30, 2016.

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

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2016		2015		2016		2015
Settlement gains on derivatives	$	—	$	3.6	$	—	$	3.6

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

	June 30, 2016 Level 2			December 31, 2015 Level 2
Commodity Swaps*	$	(0.5	)	$	13.8
Total	$	(0.5	)	$	13.8

* 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 the Partnership's and/or the counterparty credit risk of the Partnership as required under FASB ASC 820.

24

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Fair Value of Financial Instruments

The Partnership has determined the estimated fair value of its financial instruments 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, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	3,364.1	$	3,148.5	$	3,066.0	$	2,585.5
Installment Payables	$	446.5	$	451.6	$	—	$	—
Obligations under capital leases	$	12.3	$	11.5	$	16.7	$	15.6

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 $697.0 million and $414.0 million in outstanding borrowings under its revolving credit facility as of June 30, 2016 and December 31, 2015, respectively. We had $15.1 million in outstanding borrowings under our credit facility as of June 30, 2016. As borrowings under either credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the applicable credit facility. As of June 30, 2016 and December 31, 2015, the Partnership had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes and installment payables as of June 30, 2016 and December 31, 2015 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 EnLink Midstream Operating, LP. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or its affiliates or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.

(b) Environmental Issues

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting 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. In February 2016, a spill occurred at the Partnership's Kill Buck Station in the Ohio operations.  State and federal agencies were notified and clean-up response efforts were promptly executed, which significantly lessened the impact of the spill.  On April 7, 2016, the state agency determined that the clean-up recovery efforts were completed and has internally transitioned monitoring to their water quality division.  The Partnership does not anticipate a material fine or penalty by either the state or federal agencies.  Additionally, although the spill that previously occurred in the Partnership's West Virginia operations in the third quarter of 2015 is still pending, the Partnership does not believe that any fine or penalty that may be issued will be material to its operations.  Lastly, the Partnership continues to work

25

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

(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, from time to time the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and any 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 effect on its financial position, results of operations or cash flows. 

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed, owned or operated 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 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, resulting in damage to certain of the Partnership's facilities. 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 has also sued 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.

(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

26

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

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”). 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 unconsolidated affiliate 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, 2016
Product sales	$	41.9		$	399.5		$	8.9		$	288.0		$	—		$	738.3
Product sales-affiliates	72.7			15.2			22.5			0.9			(79.6		)	31.7
Midstream services	23.2			52.7			18.0			14.4			—			108.3
Midstream services-affiliates	111.9			25.5			41.7			4.0			(22.5		)	160.6
Cost of sales	(103.6		)	(425.5		)	(31.6		)	(273.8		)	102.1			(732.4		)
Operating expenses	(43.0		)	(25.4		)	(11.8		)	(19.9		)	—			(100.1		)
Loss on derivative activity	—			—			—			—			(5.7		)	(5.7		)
Segment profit	$	103.1		$	42.0		$	47.7		$	13.6		$	(5.7	)	$	200.7
Depreciation and amortization	$	(48.7	)	$	(28.6	)	$	(34.8	)	$	(10.6	)	$	(2.2	)	$	(124.9	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	57.2		$	14.1		$	63.1		$	0.9		$	4.9		$	140.2
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
Six Months Ended June 30, 2016
Product sales	$	104.4		$	687.2		$	16.7		$	518.5		$	—		$	1,326.8
Product sales-affiliates	110.0			22.6			33.1			1.1			(110.6		)	56.2
Midstream services	50.6			107.9			33.1			31.2			—			222.8
Midstream services-affiliates	222.2			38.2			86.7			9.2			(33.1		)	323.2
Cost of sales	(194.9		)	(727.6		)	(50.9		)	(488.9		)	143.7			(1,318.6		)
Operating expenses	(82.3		)	(48.7		)	(24.6		)	(42.7		)	—			(198.3		)
Loss on derivative activity	—			—			—			—			(6.1		)	(6.1		)
Segment profit	$	210.0		$	79.6		$	94.1		$	28.4		$	(6.1	)	$	406.0
Depreciation and amortization	$	(94.9	)	$	(57.9	)	$	(68.6	)	$	(21.0	)	$	(4.4	)	$	(246.8	)

27

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Impairments	$	(473.1	)	$	—		$	—		$	(93.2	)	$	(307.0	)	$	(873.3	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	80.5		$	36.8		$	132.3		$	4.2		$	6.8		$	260.6
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

The table below presents information about segment assets as of June 30, 2016 and December 31, 2015:

	June 30, 2016		December 31, 2015
Segment Identifiable Assets:	(In millions)
Texas	$	3,179.9	$	3,709.5
Louisiana	2,330.9		2,309.3
Oklahoma	2,413.6		873.4
Crude and Condensate	780.6		898.0
Corporate	1,457.3		1,751.1
Total identifiable assets	$	10,162.3	$	9,541.3

The following table reconciles the segment profits reported above to the operating income (loss) as reported in the Condensed Consolidated Statements of Operations (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Segment profits	$	200.7		$	197.2		$	406.0		$	381.8
General and administrative expenses	(30.3		)	(28.1		)	(65.4		)	(70.8		)
Loss on disposition of assets	(0.3		)	—			(0.1		)	—
Depreciation and amortization	(124.9		)	(97.7		)	(246.8		)	(189.0		)
Impairments	—			—			(873.3		)	—
Operating income (loss)	$	45.2		$	71.4		$	(779.6	)	$	122.0

28

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(17) Supplemental Cash Flow Information

The following schedule summarizes non-cash financing activities for the period presented:

	Six Months Ended   June 30,
	2016		2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	214.9	$	—
Non-cash issuance of common units of the Partnership (2)	—		180.0
Non-cash issuance of Class C Common Units of the Partnership (2)	—		180.0
Installment payable, net of discount of $79.1 million (3)	420.9		—

(1) For the six months ended June 30, 2016, non-cash common units were issued as partial consideration for the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

(2) For the six months ended June 30, 2015, non-cash common units and Class C Common Units were issued by the Partnership as partial consideration for the Coronado acquisition.

(3) The Partnership incurred installment purchase obligations, net of discount, assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

(18) Other Information

The following table presents additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following:

	June 30, 2016		December 31, 2015
	(in millions)
Accrued interest	$	23.6	$	23.2
Accrued wages and benefits, including taxes	10.3		27.7
Accrued ad valorem taxes	23.7		27.0
Capital expenditure accruals	23.6		22.3
Onerous performance obligations	16.3		17.0
Other	48.6		57.6
Other current liabilities	$	146.1	$	174.8

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ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

(19) Subsequent Events

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership's 4.850% senior notes due 2026 (the "2026 Notes") at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million will be used to repay outstanding borrowings under the Partnership's revolving credit facility and for general partnership purposes.

On August 1, 2016, the Partnership formed a joint venture with an affiliate of NGP Natural Resources XI, L.P. (“NGP”) to operate and expand its natural gas, natural gas liquids, and crude oil midstream assets in the liquids-rich Delaware Basin.  The joint venture is initially owned 50.1 percent by the Partnership and 49.9 percent by NGP. The Partnership contributed approximately $230.0 million of existing assets within the Texas segment to the joint venture and committed an additional $285.0 million in capital to fund potential future development projects and potential acquisitions. NGP committed an aggregate of approximately $400.0 million of capital, including an initial contribution of approximately $115.0 million, which the joint venture distributed to the Partnership at the formation of the joint venture to reimburse the Partnership for capital spent to date on existing assets and ongoing projects. As part of this agreement, NGP granted the Partnership graded call rights beginning in 2021 to acquire increasing portions of NGP’s interest in the joint venture at a price based upon a fixed multiple.

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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.

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 EnLink Oklahoma Gas Processing, LP and its consolidated subsidiaries (collectively, “EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.

Overview

We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. EnLink Midstream Partners, LP 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. EnLink Oklahoma T.O., a partnership owned by the Partnership and us, is engaged in the gathering and processing of natural gas. Our interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. consist of the following as of June 30, 2016:

• 88,528,451 common units representing an aggregate 23.0% limited partner interest in the Partnership;

• 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

• 16% limited partner interest in EnLink Oklahoma T.O.

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 the 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.

In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU 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. Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC is considered the primary beneficiary as it has the power to direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership. 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 EnLink Oklahoma T.O..

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 10,000 miles of pipelines, 19 natural gas processing plants, seven fractionators, 3.2 million barrels of NGL cavern storage, 19.1 Bcf of natural gas storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 150 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, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) and Central Northern Oklahoma Woodford (“CNOW”) 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

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(5) Corporate, which includes the Partnership's unconsolidated affiliate investments in Howard Energy Partners (“HEP”) in the Eagle Ford Shale, its contractual right to the economic burdens and benefits associated with Devon's ownership interest in Gulf Coast Fractionators (“GCF”) in south Texas and its 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-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 98% 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, 2016. The Partnership reflects revenue as “Product sales” and “Midstream services” 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:

• gathering and 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 same 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.

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 based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of June 30, 2016, the balance sheet reflects a liability of $53.8 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the 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

32

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 are 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.

The Partnership realizes gross operating margins from its processing services primarily through different contractual 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 POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas and 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.

Recent Developments

Acquisition

Tall Oak. On January 7, 2016, we and the Partnership acquired a 16% and 84% interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The Partnership's installment payables are valued net of discount within the total purchase price.

The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $784.2 million in cash paid by the Partnership, the majority of which was derived from the proceeds from the issuance of Preferred Units (as defined under “Issuance of Preferred Units” below), and (b) 15,564,009 of our common units issued directly by us and approximately $22.2 million in cash paid by us.

EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and CNOW plays in Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that have a remaining weighted-average term of approximately 13 years. EnLink Oklahoma T.O. assets are strategically located in the core areas of the STACK and CNOW plays and include:

• Chisholm Plant. The Chisholm Plant, which serves the STACK play, is a cryogenic gas processing plant with a current capacity of 100 MMcf/d. Depending on future volume requirements, the Chisholm Plant could be expanded by an additional 600 MMcf/d for a total processing capacity of 700 MMcf/d. The plant is connected to a 200-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

The Partnership plans to construct a new cryogenic gas processing plant, referred to as Chisholm II, that will provide an additional 200 MMcf/d of processing capacity and will be tied to new and existing pipelines in the STACK and SCOOP play.  The planned expansion is scheduled to be completed during the first quarter of 2017.  A majority of the new capacity will be supported by long-term contracts.

• Battle Ridge Plant. The Battle Ridge Plant, which provides us and the Partnership with an entry into the CNOW play, is a cryogenic gas processing plant with a current capacity of 75 MMcf/d. Depending on future volume requirements, the Battle Ridge Plant could be expanded by an additional 400 MMcf/d for a total processing capacity of 475 MMcf/d. The plant is connected to a 175-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

• Connecting Pipeline. A 42-mile, 16-inch high-pressure header pipeline with a total capacity of 150 MMcf/d was constructed to connect the Chisolm and Battle Ridge systems. The pipeline went into service in March 2016 and provides customers with additional operational flexibility.

33

Organic Growth

Greater Chickadee Crude Oil Gathering System.The Partnership will construct a new crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin that the Partnership refers to as “Greater Chickadee.” Greater Chickadee will include over 150 miles of high- and low-pressure pipelines that will transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area. Greater Chickadee also includes the construction of multiple central tank batteries and pump, truck injection, and storage stations to maximize shipping and delivery options for the Partnership's producer customers. The initial phase of Greater Chickadee will be operational in the second half of this year with full service expected early next year.

Riptide Processing Plant. In April 2016, the Partnership completed construction of the Riptide processing plant in the Permian Basin. The Riptide plant was part of the Coronado Midstream acquisition that was completed in March 2015. The Riptide plant is integrated with the Partnership's Midland Basin system, and key customers include Diamondback Energy, Inc., RSP Permian, Inc. and Reliance Energy, Inc.

Lobo II Natural Gas Gathering and Processing Facility. In the first quarter of 2016, the Partnership commenced construction of a new cryogenic gas processing plant and a gas gathering system in the Delaware Basin. The plant will initially provide 60 MMcf/d of processing capacity (with a potential capacity of 120 MMcf/d) and will be tied to approximately 75 miles of new pipeline located in both in Texas and New Mexico that is also under construction. The plant and Texas portion of the pipeline are expected to be completed in the second half of 2016 with the remaining New Mexico pipeline to be completed in the first quarter of 2017.

Marathon Petroleum Joint Venture. The Partnership has entered into a series of agreements with a subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”) to create a 50/50 joint venture named Ascension Pipeline Company, LLC. In the third quarter of 2016, the joint venture will commence construction of a new 30-mile NGL pipeline connecting the Partnership's existing Riverside fractionation and terminal complex to Marathon Petroleum's Garyville refinery located on the Mississippi River. This bolt-on project to the Partnership's Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum. Under the arrangement, the Partnership will serve as the construction manager and operator of the pipeline project, which is expected to be operational in the first half of 2017.

HEP. During 2016, the Partnership plans to make contributions to HEP, primarily to fund its equity share of HEP's Nueva Era Pipeline. The Nueva Era Pipeline is a 50-50 joint venture between HEP and Mexico-based energy and services firm Grupo Clisa that will connect HEP’s existing Webb County Hub in South Texas directly to the Mexican National Pipeline System in Monterrey, Mexico. Mexico’s Comisión Federal de Electricidad will be the foundation shipper on the approximately 200-mile, 30-inch pipeline and will transport 504 MMcf/d on the system for a 25-year term. For the three and six months ended June 30, 2016, the Partnership contributed $34.7 million and $41.8 million, respectively.

Issuance of Senior Notes

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership's 4.850% senior notes due 2026 (the "2026 Notes") at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million will be used to repay outstanding borrowings under the Partnership's revolving credit facility and for general partnership purposes.

Issuance of Partnership Units

Equity Distribution Agreement. 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, 2016, the Partnership sold an aggregate of 3.3 million common units under the BMO EDA, generating proceeds of approximately $52.3 million (net of approximately $0.5 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2016, approximately $264.4 million remains available to be issued under the agreement.

34

Issuance of Partnership Preferred Units

On January 7, 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units representing limited partner interests (the “Preferred Units”) to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund the Partnership's portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield.

The Preferred Units are convertible into the Partnership's common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership's option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the General Partner or our managing member, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, at an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the three and six months ended June 30, 2016, $18.0 million and $29.8 million of income was allocated to the preferred units, respectively.

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 EnLink Oklahoma T.O. adjusted EBITDA (as defined herein) and our interest in Midstream Holdings adjusted EBITDA (as defined herein), less our share of maintenance capital attributable to our interest in EnLink T.O. and Midstream Holdings, 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, plus our standalone impairment expense. ENLC's share of EnLink Oklahoma T.O. growth capital expenditures are funded by borrowings under ENLC's credit facility and not considered in determining ENLC's cash flow available for distribution. Cash available for distribution is a supplemental liquidity 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.

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 (loss). Cash available for distribution should not be considered as an alternative to GAAP net income (loss). 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 (loss) 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.

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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,
	2016			2015			2016			2015
	(unaudited)
Distribution declared by ENLK associated with (1):
General partner interest	$	0.5		$	0.6		$	1.1		$	1.2
Incentive distribution rights	14.2			11.3			28.0			20.1
ENLK common units owned	34.5			24.3			69.0			36.6
Total share of ENLK distributions declared	$	49.2		$	36.2		$	98.1		$	57.9
Transferred interest EBITDA (2)	—			15.6			—			53.7
Adjusted EBITDA of EnLink Oklahoma T.O. (3)	2.1			—			3.0			—
Transaction costs (4)	(0.1		)	—			0.6			—
Total cash available	$	51.2		$	51.8		$	101.7		$	111.6
Uses of cash:
General and administrative expenses	(1.1		)	(1.0		)	(2.9		)	(1.8		)
Current income taxes (5)	—			2.9			—			(1.2		)
Interest expense	(0.3		)	(0.1		)	(0.6		)	(0.4		)
Maintenance capital expenditures (6)	—			(1.6		)	—			(4.0		)
Total cash used	$	(1.4	)	$	0.2		$	(3.5	)	$	(7.4	)
ENLC cash available for distribution	$	49.8		$	52.0		$	98.2		$	104.2

(1) Represents distributions to be paid to us on August 11, 2016 and distributions paid May 12, 2016, August 14, 2015 and May 14, 2015.

(2) Represents our interest in EnLink Midstream Holdings, LP's (“Midstream Holdings”) adjusted EBITDA, which was disbursed to ENLC by Midstream Holdings on a monthly basis prior to the transfer of all interests in Midstream Holdings to the Partnership in drop down transactions (the “EMH Drop Downs”). Midstream Holdings’ adjusted EBITDA is defined as earnings plus depreciation, provision for income taxes and distributions from equity investments less income from equity investment.

(3) Represents our interest in EnLink Oklahoma T.O. adjusted EBITDA, which is disbursed to ENLC by EnLink Oklahoma T.O. on a monthly basis. EnLink Oklahoma T.O. adjusted EBITDA is defined as earnings before depreciation and amortization and provision for income taxes.

(4) Represents acquisition transaction costs attributable to the Company’s 16% interest in Enlink Oklahoma T.O which are considered growth capital expenditures as part of the cost of the assets acquired.

(5) Represents our stand-alone current tax expense.

(6) Represents our 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. There are no maintenance capital expenditures attributable to ENLC's share of EnLink Oklahoma T.O. during 2016. All of EnLink Oklahoma T.O. capital expenditures during 2016 are growth related which are not considered in determining cash flow available for distribution.

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

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
	(unaudited)
Net income (loss) of ENLC	$	1.2		$	44.6		$	(870.1	)	$	69.6
Less: Net income (loss) attributable to ENLK	5.0			55.5			(555.4		)	91.1
Net loss of ENLC excluding ENLK	$	(3.8	)	$	(10.9	)	$	(314.7	)	$	(21.5	)
ENLC's share of distributions from ENLK (1)	49.2			36.2			98.1			57.9
ENLC's interest in EnLink Oklahoma T.O. depreciation	3.6			—			6.8			—
ENLC deferred income tax (benefit) expense (2)	0.5			12.4			(0.3		)	17.8
Maintenance capital expenditures (3)	—			(1.6		)	—			(4.0		)
Transferred interest EBITDA (4)	—			15.6			—			53.7
ENLC corporate goodwill impairment	—			—			307.0			—
Other items (5)	0.3			0.3			1.3			0.3
ENLC cash available for distribution	$	49.8		$	52.0		$	98.2		$	104.2

(1) Represents distributions declared by ENLK and to be paid to ENLC on August 11, 2016 and distributions paid by ENLK to ENLC on May 12, 2016, August 14, 2015, and May 14, 2015.

(2) Represents our stand-alone deferred taxes.

(3) There are no maintenance capital expenditures attributable to ENLC's share of EnLink Oklahoma T.O. during 2016. All of EnLink Oklahoma T.O. capital expenditures during 2016 are growth related which are not considered in determining cash flow available for distribution. For the three and six month periods ended June 30, 2015, the amounts represent ENLC’s interest in maintenance capital expenditures of Midstream Holdings prior to the EMH Drop Downs during the first half of 2015.

(4) Represents our interest in the adjusted EBITDA of Midstream Holdings prior to the EMH Drop Downs. Adjusted EBITDA of Midstream Holdings' is defined as maintenance capital expenditures prior to the EMH Drop Downs netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA.

(5) Represents transaction costs attributable to our share of the acquisition of EnLink Oklahoma T.O. and other non-cash items not included in cash available for distributions.

Gross Operating Margin

We define gross operating margin 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, operating income (loss) 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 operating income (loss) to gross operating margin:

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2016		2015		2016			2015
	(in millions)
Operating income (loss)	$	45.2	$	71.4	$	(779.6	)	$	122.0
Add (Deduct):
Operating expenses	100.1		109.1		198.3			207.6
General and administrative expenses	30.3		28.1		65.4			70.8
Depreciation and amortization	124.9		97.7		246.8			189.0
Loss on disposition of assets	0.3		—		0.1			—
Impairments	—		—		873.3			—
Total gross operating margin	$	300.8	$	306.3	$	604.3		$	589.4

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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:

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
	(in millions, except volumes)
Texas Segment
Revenues	$	249.7		$	268.0		$	487.2		$	478.8
Cost of sales	(103.6		)	(118.4		)	(194.9		)	(185.6		)
Total gross operating margin	$	146.1		$	149.6		$	292.3		$	293.2
Louisiana Segment
Revenues	$	492.9		$	481.7		$	855.9		$	919.0
Cost of sales	(425.5		)	(418.2		)	(727.6		)	(789.1		)
Total gross operating margin	$	67.4		$	63.5		$	128.3		$	129.9
Oklahoma Segment
Revenues	$	91.1		$	40.7		$	169.6		$	86.3
Cost of sales	(31.6		)	(2.0		)	(50.9		)	(7.1		)
Total gross operating margin	$	59.5		$	38.7		$	118.7		$	79.2
Crude and Condensate Segment
Revenues	$	307.3		$	518.9		$	560.0		$	786.0
Cost of sales	(273.8		)	(465.6		)	(488.9		)	(700.3		)
Total gross operating margin	$	33.5		$	53.3		$	71.1		$	85.7
Corporate
Revenues	$	(107.8	)	$	(34.8	)	$	(149.8	)	$	(55.1	)
Cost of sales	102.1			36.0			143.7			56.5
Total gross operating margin	$	(5.7	)	$	1.2		$	(6.1	)	$	1.4
Total
Revenues	$	1,033.2		$	1,274.5		$	1,922.9		$	2,215.0
Cost of sales	(732.4		)	(968.2		)	(1,318.6		)	(1,625.6		)
Total gross operating margin	$	300.8		$	306.3		$	604.3		$	589.4
Midstream Volumes:
Texas
Gathering and Transportation (MMBtu/d)	2,651,000			2,727,800			2,697,200			2,739,300
Processing (MMBtu/d)	1,194,200			1,262,000			1,196,200			1,199,500
Louisiana
Gathering and Transportation (MMBtu/d)	1,576,200			1,383,300			1,525,600			1,369,400
Processing (MMBtu/d)	483,600			520,400			500,700			477,600
NGL Fractionation (Gals/d)	5,303,700			5,660,200			5,162,000			5,628,800
Oklahoma
Gathering and Transportation (MMBtu/d)	619,300			413,000			618,200			422,400
Processing (MMBtu/d)	575,600			268,200			572,600			312,100
Crude and Condensate
Crude Oil Handling (Bbls/d)	97,700			141,000			111,200			122,400
Brine Disposal (Bbls/d)	3,300			3,700			3,400			3,700

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Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Gross Operating Margin. Gross operating margin was $300.8 million for the three months ended June 30, 2016 as compared to $306.3 million for the three months ended June 30, 2015, a decrease of $5.5 million, or 1.8%. The overall decrease in gross operating margin was the result of declines in gross operating margins from the Partnership's Crude and Condensate and Texas segments primarily due to volume declines as discussed more fully below. These decreases were partially offset by gross operating margin contributions totaling $22.9 million from the Partnership's acquisitions in Texas and Oklahoma during 2015 and 2016. The following provides additional details regarding these changes in gross operating margin by segment:

• Texas Segment. The Texas segment had a decrease in gross operating margin of $3.5 million for the three months ended June 30, 2016 compared to the three months ended June 30, 2015. The Texas segment decrease was primarily

attributable to a decrease of $10.2 million in gross operating margin from the Partnership's north Texas processing, gathering, and transmission assets primarily due to volume declines and the expiration of certain higher margin contracts. This decrease was partially offset by gross operating margin contributions totaling $3.9 million during 2016 from the Matador and Deadwood assets acquired in the fourth quarter of 2015. In addition, volume growth in the Midland Basin resulted in an additional increase in gross operating margin of $2.9 million between periods.

• Louisiana Segment. The Louisiana segment had an increase in gross operating margin of $3.9 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The Partnership's NGL business accounted for $3.7 million of this increase primarily due to the impact of price changes between periods on its product inventories.

• Oklahoma Segment. The Oklahoma segment had an increase in gross operating margin of $20.8 million for the three months ended June 30, 2016 compared to the three months ended June 30, 2015. This increase was driven by a gross operating margin contribution of $19.0 million from the Tall Oak assets acquired in January 2016. In addition, the Partnership's gross operating margin from the Cana gathering and processing assets increased by $1.9 million between periods because the Cana processing plant, which was shut down for part of the second quarter of 2015 for repairs, was fully operational in the second quarter of 2016.

• Crude & Condensate Segment. The Crude and Condensate segment had a decrease in gross operating margin of $19.8 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. $12.0 million of this decrease was the result of the termination of a customer contract during the second quarter of 2015, including a $10.3 million early termination payment. The remaining decrease of $7.3 million was primarily due to volume declines throughout the Crude and Condensate segment.

• Corporate Segment. The Corporate segment included a loss from derivative activity of $5.7 million for the three months ended June 30, 2016 as compared to a gain of $1.2 million for the comparative period during 2015 primarily due to unrealized losses related to the changes in the fair value of the Partnership's commodity swaps between periods.

Operating Expenses. Operating expenses were $100.1 million for the three months ended June 30, 2016 as compared to $109.1 million for the three months ended June 30, 2015, a decrease of $9.0 million, or 8.2%. The primary contributors to the total decrease by segment were as follows:

	Three Months Ended    June 30,				Change
	2016		2015		$			%
	(in millions)
Texas Segment	$	43.0	$	45.5	$	(2.5	)	(5.5	)%
Louisiana Segment	25.4		27.2		(1.8		)	(6.6	)%
Oklahoma Segment	11.8		9.1		2.7			29.7	%
Crude and Condensate Segment	19.9		27.3		(7.4		)	(27.1	)%
Total	$	100.1	$	109.1	$	(9.0	)	(8.2	)%

• Texas Segment. Operating expenses in the Partnership's Texas segment decreased $2.5 million for the three months ended June 30, 2016 as compared to the same three month period during 2015. Of this decrease, $1.0 million was attributable to reduced taxes related to operating activities, and the remaining decrease of $2.1 million was attributable to cost reduction measures together with timing of field work. These decreases were partially offset by a $1.0 million increase in operating expenses attributable to the October 2015 Matador acquisition.

• Louisiana Segment. Operating expenses in the Partnership's Louisiana segment decreased $1.8 million for the three months ended June 30, 2016 as compared to the same three month period during 2015. This decrease was primarily attributable to cost reduction measures.

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• Oklahoma Segment. Operating expenses in the Partnership's Oklahoma segment increased $2.7 million for the three months ended June 30, 2016 as compared to the same three month period during 2015. Of this increase, $5.1 million was attributable to the January 2016 Tall Oak acquisition. This increase was partially offset by a $2.2 million decrease in repair expenses at the Partnership's Cana Plant between periods.

• Crude & Condensate Segment. Operating expenses in the Partnership's Crude and Condensate segment decreased $7.4 million for the three months ended June 30, 2016 as compared to the same three month period during 2015. Of this decrease, $3.4 million was attributable to reduced vehicle maintenance, transportation, service fees, and fuel expenses as a result of decreased trucking volumes within the Partnership's ORV and LPC assets, $2.0 million was attributable to reduced labor costs, and $1.3 million was attributable to cost reduction measures.

General and Administrative Expenses. General and administrative expenses were $30.3 million for the three months ended June 30, 2016 as compared to $28.1 million for the three months ended June 30, 2015, an increase of $2.2 million, or 7.8%. The primary contributors to the increase were as follows:

• the Partnership's wages & salaries increased by $1.8 million due to severance payments during the second quarter of 2016 and an increase in bonus expense between comparative three month periods;

• the Partnership's rent expense increased $1.2 million related to new office leases, which commenced during 2016; and

• the Partnership's unit-based compensation expense decreased $0.9 million.

Depreciation and Amortization. Depreciation and amortization expenses were $124.9 million for the three months ended June 30, 2016 as compared to $97.7 million for the three months ended June 30, 2015, an increase of $27.2 million, or 27.8%. Of this increase in depreciation and amortization expense, $22.1 million was attributable to the acquisition of the EnLink Oklahoma T.O. assets from Tall Oak in January 2016, $2.8 million was attributable to the Matador acquisition in October 2015, $0.5 million was related to the 50% Deadwood acquisition on November 2015. These increases were partially offset by a $5.4 million decrease in amortization attributable to the impairment of ORV intangible assets in August 2015. The remaining increase in depreciation and amortization expense was primarily attributable to assets placed in service.

Interest Expense. Interest expense was $46.5 million for the three months ended June 30, 2016 as compared to $22.6 million for the three months ended June 30, 2015, an increase of $23.9 million, or 105.8%. Of the increase in interest expense, $11.3 million was attributable to an increase in average debt in 2016 compared to 2015, $13.3 million was attributable to an increase in non-cash amortization of discount due to the Tall Oak acquisition installment payments, and $0.8 million was attributable to an increase in non-cash interest expense related to the change in the valuation of our mandatorily redeemable non-controlling interest. This increase was partially offset by a gain on the settlement of interest rate swaps of $3.6 million in 2015, with no comparable gain during 2016. Net interest expense consisted of the following (in millions):

	Three Months Ended    June 30,
	2016			2015
Partnership senior notes	$	30.0		$	25.6
Partnership credit facility	4.2			2.2
Credit facility	0.2			0.2
Capitalized interest	(1.6		)	(1.6		)
Amortization of debt issue costs and net discounts (premium)	13.6			0.1
Cash settlements on interest rate swaps	—			(3.6		)
Mandatory redeemable non-controlling interest	0.1			(0.7		)
Other	—			0.4
Total	$	46.5		$	22.6

Income (loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was$0.8 million for the three months ended June 30, 2016 compared to income of $5.9 million for the three months ended June 30, 2015, a decrease of $5.1 million. This decrease was primarily due to a decline of $2.4 million in income from the Partnership's GCF investment between periods primarily due to decreased supply volumes and reduced fractionation fees. An additional decrease of $2.7 million was due to a decrease in income from the Partnership's investment in HEP, which was primarily attributable to increased interest, depreciation, and amortization expense resulting from acquisitions by HEP.

Income Tax Provision. Income tax benefit was $1.8 million for the three months ended June 30, 2016 as compared to income tax expense of $10.2 million for the three months ended June 30, 2015, a decrease of $12.0 million. The decrease in income tax expense was primarily attributable to a decrease in taxable income between periods. See Note 7 to the condensed consolidated financial statements titled “Income Taxes” for further details.

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Net Income (Loss) Attributable to Non-controlling Interest. Net income attributable to non-controlling interest was $0.4 million for the three months ended June 30, 2016 as compared to net income of $28.4 million for the three months ended June 30, 2015, a decrease of $28.0 million. This decrease was due to lower net income in 2016 at the Partnership.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Gross Operating Margin. Gross operating margin was $604.3 million for the six months ended June 30, 2016 as compared to $589.4 million for the six months ended June 30, 2015, an increase of $14.9 million, or 2.5%. The overall increase in gross operating margin was due to acquisitions in the Partnership's Texas and Oklahoma segments during 2015 and 2016 which contributed an aggregate increase of $47.5 million in gross operating margin between periods. This increase was partially offset by declines in gross operating margins from the Partnership's other assets primarily due to volume declines and certain contract expirations as discussed more fully below. The following provides additional details regarding these changes in gross operating margin by segment:

• Texas Segment. The Texas segment had a decrease in gross operating margin of $0.9 million for the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The Texas segment decrease was attributable to a decrease of $19.3 million in gross operating margin due to volume declines and the expiration of certain higher margin contracts from the Partnership's north Texas processing, gathering, and transportation assets. This decrease was partially offset by gross operating margin contributions totaling $15.7 million for the Coronado assets acquired in March 2015 and the Matador and Deadwood assets acquired during the fourth quarter of 2015. In addition, volume growth in the Midland Basin resulted in an additional increase in gross operating margin of $2.9 million between periods.

• Louisiana Segment. The Louisiana segment had a decrease in gross operating margin of $1.6 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. This decrease was primarily attributable to reductions in volumes at the Partnership's north Louisiana gathering and transportation assets.

• Oklahoma Segment. The Oklahoma segment had an increase in gross operating margin of $39.5 million for the six months ended June 30, 2016 compared to the six months ended June 30, 2015. This increase was driven by a gross operating margin contribution of $31.8 million from the Tall Oak assets acquired in January 2016. In addition, the Partnership's gross operating margin from the Cana gathering and processing assets increased by $7.0 million between periods primarily due to increased volumes combined with the expansion of the Partnership's compression facilities, which was completed in October 2015.

• Crude & Condensate Segment. The Crude and Condensate segment had a decrease in gross operating margin of $14.6 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. $14.4 million of this decrease was the result of the termination of a customer contract during the second quarter of 2015, including a $10.3 million early termination payment. The negative impact on gross operating margin due to lower crude oil and condensate volumes during the first half of 2016 as compared to the same period in 2015 was offset by increased gross operating margin contributions from our newly-constructed ORV compression and condensate stabilization facilities, which commenced operation during late 2015.

• Corporate Segment. The Corporate segment included a loss from derivative activity of $6.1 million for the six months ended June 30, 2016 as compared to a gain of $1.4 million for the comparative period during 2015 primarily due to unrealized losses related to the changes in the fair value of the Partnership's commodity swaps between periods.

Operating Expenses. Operating expenses were $198.3 million for the six months ended June 30, 2016 as compared to $207.6 million for the six months ended June 30, 2015, a decrease of $9.3 million, or 4.5%. The primary contributors to the decrease by segment were as follows:

	Six Months Ended   June 30,				Change
	2016		2015		$			%
	(in millions)
Texas Segment	$	82.3	$	92.6	$	(10.3	)	(11.1	)%
Louisiana Segment	48.7		51.5		(2.8		)	(5.4	)%
Oklahoma Segment	24.6		16.1		8.5			52.8	%
Crude and Condensate Segment	42.7		47.4		(4.7		)	(9.9	)%
Total	$	198.3	$	207.6	$	(9.3	)	(4.5	)%

• Texas Segment. Operating expenses in the Partnership's Texas segment decreased $10.3 million for the six months ended June 30, 2016 as compared to the same six month period during 2015. The decrease was primarily attributable to $2.0 million in reduced taxes related to operating activities, and $15.1 million due to lower costs resulting from reduced activity

42

and cost savings measures. These decreases were partially offset by a $6.7 million increase in operating expenses attributable to the March 2015 Coronado acquisition, the October 2015 the Matador acquisition and November 2015 Deadwood acquisition.

• Louisiana Segment. Operating expenses in the Partnership's Louisiana segment decreased $2.8 million for the six months ended June 30, 2016 as compared to the same six month period during 2015. This decrease was primarily attributable to realized cost savings from materials and supplies, contract services, and labor due to cost reduction measures.

• Oklahoma Segment. Operating expenses in the Partnership's Oklahoma segment increased $8.5 million for the six months ended June 30, 2016 as compared to the same six-month period in 2015. The increase was primarily attributable to the January 2016 Tall Oak acquisition.

• Crude & Condensate Segment. Operating expenses in the Partnership's Crude and Condensate segment decreased $4.7 million for the six months ended June 30, 2016 as compared to the same six month period during 2015. The decrease was partially attributable to a $1.1 million decrease in labor costs. Additional decreases in operating expenses were primarily due to reduced activity within the Partnership's ORV and LPC operations.

General and Administrative Expenses. General and administrative expenses were $65.4 million for the six months ended June 30, 2016 as compared to $70.8 million for the six months ended June 30, 2015, a decrease of $5.4 million, or 7.6%. The primary contributors to the total decrease were as follows:

• the Partnership unit-based compensation expense decreased $6.5 million primarily due to bonuses being paid in the form of units that immediately vested in March 2015;

• the Partnership software consulting fees decreased $1.9 million;

• the Partnership transition service fees associated with acquisitions decreased by $1.0 million;

• the Partnership wages & salaries increased by $1.6 million due to severance expense during 2016; and

• the Partnership rent expense increased $1.7 million related to the new office leases, which commenced during 2016.

Depreciation and Amortization. Depreciation and amortization expenses were $246.8 million for the six months ended June 30, 2016 as compared to $189.0 million for the six months ended June 30, 2015, an increase of $57.8 million, or 30.6%. Of this increase in depreciation and amortization expense, $41.9 million was attributable to the acquisition of the EnLink Oklahoma T.O. assets in January 2016, $7.8 million was attributable to the acquisition of the Coronado assets in March 2015, $4.3 million was attributable to the Matador acquisition in October 2015, $1.0 million was related to the 50% Deadwood acquisition in November 2015 and $1.7 million was attributable to the decommissioning of certain pipeline assets in Louisiana. These increases were partially offset by a $10.8 million decrease in amortization attributable to the impairment of ORV intangible assets in August 2015. The remaining increase in depreciation and amortization expense was primarily attributable to assets placed in service.

Impairments. Impairment expense was $873.3 million for the six months ended June 30, 2016. During March 2016, we recognized an impairment on goodwill of $566.3 million related to the Partnership's Texas and Crude and Condensate segments, and $307.0 million related to our Corporate segment. For more information, see “Critical Accounting Policies-Impairment of Goodwill” below.

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Interest Expense. Interest expense was $90.5 million for the six months ended June 30, 2016 as compared to $41.7 million for the six months ended June 30, 2015, an increase of $48.8 million, or 117.0%. Of the increase in interest expense, $21.8 million was attributable to an increase in average debt in 2016 compared to 2015, $25.7 million was attributable to an increase in non-cash amortization of discount due to the Tall Oak acquisition installment payments, and $3.6 million is attributable to an increase in non-cash interest expense related to the change in the valuation of our mandatorily redeemable non-controlling interest. This increase was partially offset by a gain on the settlement of interest rate swaps of $3.6 million in 2015, with no comparable gain during 2016. Net interest expense consisted of the following (in millions):

	Six Months Ended   June 30,
	2016			2015
Partnership senior notes	$	60.0		$	45.9
Partnership credit facility	7.4			4.5
Credit facility	0.4			0.3
Capitalized interest	(4.2		)	(2.9		)
Amortization of debt issue costs and net discounts (premium)	26.2			—
Cash settlements on interest rate swaps	—			(3.6		)
Mandatory redeemable non-controlling interest	0.3			(3.3		)
Other	0.4			0.8
Total	$	90.5		$	41.7

Income (loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was$1.6 million for the six months ended June 30, 2016 as compared to income of $9.7 million for the six months ended June 30, 2015, a decrease of $11.3 million. This decrease was primarily due to a decline of $7.5 million in income from the Partnership's GCF investment due to a $4.3 million decrease in revenue due to lower pipeline and fractionation volumes as well as a $3.0 million increase in operating costs for major scheduled fractionator maintenance during the first six months of 2016. An additional decrease of $3.8 million was due to decreased income from the Partnership's investment in HEP, which was primarily attributable to $6.0 million in increased interest, depreciation, and amortization expense resulting from acquisitions, partially offset by increased net operating income (revenue less cost of sales, operating expenses and general and administrative expenses) of $2.4 million.

Income Tax Provision. Income tax benefit was $1.6 million for the six months ended June 30, 2016 as compared to income tax expense of $20.9 million for the six months ended June 30, 2015, a decrease of $22.5 million. The decrease in income tax expense was primarily attributable to a decrease in taxable income between periods. Although we realized a net loss before income taxes of $871.7 million during the six months ended June 30, 2016, we did not realize a larger tax benefit as substantially all of the loss was the result of a goodwill impairment recognized during the three months ended March 31, 2016, which is treated as a permanent difference for tax. See Note 7 to the condensed consolidated financial statements titled “Income Taxes” for further details.

Net Income (Loss) Attributable to Non-controlling Interest. Net loss attributable to non-controlling interest was $413.3 million for the six months ended June 30, 2016 as compared to net income of $36.4 million for the six months ended June 30, 2015, a decrease of $449.7 million. This decrease was primarily due to impairments at the Partnership which resulted in lower net income in 2016.

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, 2015, except as described below.

Impairment of Goodwill. We conduct an annual goodwill impairment test in the fourth quarter each year. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During the first quarter of 2016, we determined that continued further weakness in the overall energy sector driven by low commodity prices together with a further decline in our unit price and the Partnership's unit

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price subsequent to year-end caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis on all reporting units.

We and the Partnership perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments. We use a market approach to perform the assessment for our Corporate reporting unit. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, control premium and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors.

Using the fair value approaches described above, in step one of the goodwill impairment test, we and the Partnership determined that the estimated fair values of the Partnership's Texas and Crude and Condensate reporting units and our Corporate reporting unit were less than their respective carrying amounts. At the Partnership's Texas and Crude and Condensate reporting units, this is primarily related to increases in the discount rate subsequent to year-end. For our Corporate reporting unit, this is primarily due to a further decline in our unit price subsequent to year-end. The second step of the goodwill impairment test at the Partnership measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized for the three months ended March 31, 2016, which is included in our six months ended June 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.

The Partnership concluded that the fair value of goodwill of the Partnership's Oklahoma reporting unit substantially exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with the remaining reporting unit is recoverable. However, the fair value of the Partnership's Texas reporting unit and our Corporate reporting unit are not substantially in excess of their carrying value. As of March 31, 2016, the fair value of the Partnership's Texas reporting unit and our Corporate reporting unit approximated its carrying value after considering the impairment loss above. As of June 30, 2016, we had $231.1 million of goodwill allocated to the Partnership's Texas reporting unit and $1,119.9 million allocated to our Corporate reporting unit.

Our and the Partnership's respective impairment determination involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our and the Partnership's assumptions and estimates, or assumptions and estimates change due to new information, we and the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The estimated fair values of our Corporate reporting unit and the Partnership's Texas reporting unit may be impacted in the future by a further decline in our unit price or the Partnership's unit price or a continuing prolonged period of lower commodity prices which may adversely affect the Partnership's estimate of future cash flows all of which could result in future goodwill impairment charges.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $304.2 million for the six months ended June 30, 2016 compared to $277.0 million for the six months ended June 30, 2015. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

	Six Months Ended   June 30,
	2016			2015
Operating cash flows before changes in working capital	$	307.6		$	301.8
Changes in working capital	$	(3.4	)	$	(24.8	)

The primary reason for the increase in operating cash flows before changes in working capital of $5.8 million from 2015 to 2016 relates to an increase in gross operating margin from the acquisition of Coronado, Matador, Deadwood and EnLink Oklahoma T.O. assets, which is partially offset by a decrease in gross operating margin in the Partnership's Crude and Condensate segment due to lower volumes and the termination of a customer contract during the second quarter of 2015. The change in working capital for 2016 related to fluctuations in trade receivable and payable balances is due to timing of collection and payments and changes in inventory balances attributable to normal operating fluctuations.

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Cash Flows from Investing Activities. Net cash used in investing activities was $1,105.7 million for the six months ended June 30, 2016 and $665.0 million for the six months ended June 30, 2015. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):

	Six Months Ended   June 30,
	2016			2015
Growth capital expenditures	$	275.1		$	322.9
Maintenance capital expenditures	13.1			26.3
Acquisition of businesses	791.3			324.8
Proceeds from sale of property	(0.8		)	(0.1		)
Investment in unconsolidated affiliate investments	41.8			—
Distribution from unconsolidated affiliate investments in excess of earnings	(14.8		)	(8.9		)
Total	$	1,105.7		$	665.0

Growth capital expenditures decreased $47.8 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The decrease is primarily attributable to the completions of the E2 compression and stabilization facilities and the VEX pipeline in the Crude and Condensate segment and the Bearkat natural gas processing plant and rich gas gathering system in 2015 in the Partnership's Texas segment. The decrease in expenditures due to the completion of these capital projects was partially offset by an increase in growth capital expenditures in the Partnership's Oklahoma segment for the EnLink Oklahoma T.O. assets.

Maintenance capital expenditures decreased $13.2 million for the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The decrease is primarily attributable to decreases in compressor overhauls and repairs in the Partnership's Texas and Oklahoma segments due to a decrease in activity and a decrease in well connects in the Partnership's Oklahoma segment.

Acquisition expenditures increased $466.5 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. Acquisition expenditures during the six months ended June 30, 2016 included the Tall Oak acquisition. Acquisition expenditures during the six months ended June 30, 2015 included the LPC and Coronado acquisitions.

During the second quarter of 2016, we had an investment in an unconsolidated affiliate of $41.8 million related to the Partnership’s contributions to HEP. Although the Partnership is receiving quarterly distributions from HEP, the Partnership’s quarterly contributions to HEP to fund its share of HEP’s Nueva Era Pipeline (discussed above under “Recent Developments”) are expected to be in excess of such distributions during 2016.

Cash Flows from Financing Activities. Net cash provided by financing activities was $793.7 million and $391.6 million for the six months ended June 30, 2016 and 2015, respectively. Our primary financing activities consist of the following (in millions):

	Six Months Ended   June 30,
	2016			2015
Net borrowings (repayments) on Partnership's credit facility	$	282.8		$	(87.1	)
Net borrowings on Company's credit facility	15.1			—
Unsecured Partnership senior notes borrowings	—			893.3
Net repayments under capital lease obligations	(2.1		)	(1.6		)
Debt financing costs	(0.4		)	(9.5		)
Proceeds from issuance of Partnership common units	52.3			4.1
Proceeds from issuance of Partnership preferred units	724.1			—

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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, 2016 and 2015 were as follows (in millions):

	Six Months Ended   June 30,
	2016		2015
Distributions to members	$	92.7	$	79.3
Distributions to non-controlling partners	186.6		175.7
Distributions to Devon for net assets acquired (1)	—		171.0

(1) Represents distributions to Devon relating to the VEX assets.

The Partnership received contributions from Devon of $1.4 million and $2.2 million for the six months ended June 30, 2016 and 2015, respectively, which related to the reimbursement of employee costs. For the six months ended June 30, 2015, the Partnership also received a contribution from Devon of $26.6 million related to the VEX pipeline.

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. Changes in drafts payable for the six months ended June 30, 2016 and 2015 were as follows (in millions):

	Six Months Ended   June 30,
	2016		2015
Decrease in drafts payable	$	—	$	(12.4	)

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, resulting in damage to certain of the Partnership's facilities. 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 has also sued 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.

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.

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, well connections, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

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The Partnership expects to fund its remaining 2016 capital expenditures, including capital contributions to its unconsolidated affiliate investments, as follows (in millions):

	2016
Growth Capital Expenditures
Texas segment	$	80 - 120
Louisiana segment		25 - 35
Oklahoma segment		110 - 140
Crude and Condensate segment		65 - 70
Corporate segment		0 - 0
Total	$	280 - 365
Maintenance Capital Expenditures	$	15.0

The Partnership's primary capital projects for 2016 include construction of its Lobo II plant and gathering system in its Texas segment, commencing construction of its Marathon joint venture NGL pipeline in its Louisiana segment, developing its EnLink Oklahoma T.O. assets in its Oklahoma segment and investing in HEP to fund its equity share of HEP's pipeline expansion projects in its Corporate segment. See “Recent Developments” for further details.

The Partnership expects to fund the remaining growth capital expenditures from the proceeds of borrowing under the Partnership credit facility discussed below and proceeds from other debt and equity sources, including its recently announced joint venture with NGP Natural Resources XI, L.P. (“NGP”). On August 1, 2016, the Partnership formed a joint venture with an affiliate of NGP to operate and expand our natural gas, natural gas liquids, and crude oil midstream assets in the liquids-rich Delaware Basin.  The joint venture is initially owned 50.1 percent by the Partnership and 49.9 percent by NGP. The Partnership contributed approximately $230.0 million of existing assets within the Texas segment to the joint venture and committed an additional $285.0 million in capital to fund potential future development projects and potential acquisitions. NGP committed an aggregate of approximately $400.0 million of capital, including an initial contribution of approximately $115.0 million, which the joint venture distributed to the Partnership at the formation of the joint venture to reimburse it for capital spent to date on existing assets and ongoing projects. The Company expects to fund its share of EnLink Oklahoma T.O. growth capital expenditures from the proceeds of borrowings under its credit facility. The Partnership expects to fund its 2016 maintenance capital expenditures from operating cash flows. In 2016, 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 to fund planned capital expenditures and to make acquisitions will depend upon 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, 2016.

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Total Contractual Cash Obligations. A summary of contractual cash obligations as of June 30, 2016 is as follows (in millions):

	Payments Due by Period
	Total		Remainder  2016		2017		2018		2019		2020		Thereafter
Long-term debt obligations	$	2,662.5	$	—	$	—	$	—	$	400.0	$	—	$	2,262.5
Partnership credit facility	697.0		—		—		—		—		697.0		—
Company credit facility	15.1		—		—		—		15.1		—		—
Interest payable on fixed long-term debt obligations	1,783.3		60.0		120.0		120.0		114.6		109.2		1,259.5
Capital lease obligations	13.6		2.0		5.4		2.9		1.5		1.8		—
Operating lease obligations	139.5		10.6		18.6		17.0		11.9		8.7		72.7
Purchase obligations	17.0		17.0		—		—		—		—		—
Delivery contract obligation	53.8		9.0		17.9		17.9		9.0		—		—
Pipeline capacity and deficiency agreements (1)	100.6		5.7		13.7		15.3		11.3		8.1		46.5
Inactive easement commitment (2)	7.0		1.0		1.0		1.0		1.0		1.0		2.0
Installment payable obligations (3)	500.0		—		250.0		250.0		—		—		—
Total contractual obligations	$	5,989.4	$	105.3	$	426.6	$	424.1	$	564.4	$	825.8	$	3,643.2

(1) Consists of pipeline capacity payments for firm transportation and deficiency agreements to secure take-away capacity for our supply contracts.  Amounts do not take into consideration costs passed back to customers.

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

(3) Amounts relate to the Partnership's partial consideration of the Tall Oak acquisition with balances due on January 7, 2017 and 2018.

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, 2016, the cash obligation for interest expense on the Partnership’s credit facility would be approximately $15.3 million per year or approximately $7.7 million for the remainder of 2016.

The interest payable under the Company'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, 2016, the cash obligation for interest expense on the Company’s credit facility would be approximately $0.6 million per year or approximately $0.3 million for the remainder of 2016.

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Indebtedness

As of June 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):

	June 31, 2016			December 31, 2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively	$	697.0		$	414.0
Company credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at June 30, 2016 was 4.25%	15.1			—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.3 million at June 30, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%	399.7			399.6
The Partnership's senior unsecured notes (due 2022), including a premium of $17.5 million at June 30, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%	180.0			181.4
The Partnership's senior unsecured notes (due 2024), net of premium of $2.7 million at June 30, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%	552.7			552.9
The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at June 30, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%	748.8			748.8
The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at June 30, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%	349.8			349.8
The Partnership's senior unsecured notes (due 2045), net of discount of $6.8 million at June 30, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%	443.2			443.1
Debt issuance cost, net of amortization of $7.0 million at June 30, 2016 and $5.1 million at December 31, 2015.	(22.2		)	(23.8		)
Other debt	—			0.2
Debt classified as long-term	$	3,364.1		$	3,066.0

Company Credit Facility. The Company has 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) 88,528,451 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the credit facility.

As of June 30, 2016 there were $15.1 million borrowings under the credit facility, leaving approximately $234.9 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility.  As of June 30, 2016, there were $11.1 million in outstanding letters of credit and $697.0 million of outstanding borrowings under the Partnership’s credit facility, leaving approximately $791.9 million available for future borrowing based on the borrowing capacity of $1.5 billion. The Partnership's credit facility will mature on March 6, 2020, unless the Partnership requests, and the requisite lenders agree, to extend it pursuant to its terms.

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

Recent Accounting Pronouncements

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet as of March 31, 2016.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which will update ASU 2014-09, Revenue from Contracts with Customers (“ASU

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2014-09”). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2016-12 has the same effective date and transition requirements as ASU 2014-09, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. The update will have no impact on our condensed consolidated financial statements or related disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

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 Partnership'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.

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

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clear through clearinghouses. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC's original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In June 2016, the CFTC proposed certain refinements to the previously proposed positions limits rules. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on us is uncertain at this time.

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 four main types of contractual arrangements as summarized below. Approximately 90% of our processing margins are from fixed-fee based contracts for the six months ended June 30, 2016.

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.Fixed-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.

52

The following table sets forth certain information related to derivative instruments outstanding at June 30, 2016 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 2016 - December 2016	Ethane	273	(MBbls)	$0.2942/gal	Index	$	(0.4	)
July 2016 - June 2017	Propane	557	(MBbls)	Index	$0.7241/gal	4.2
July 2016 - June 2017	Normal Butane	122	(MBbls)	Index	$0.5814/gal	(0.6		)
July 2016 - June 2017	Natural Gasoline	66	(MBbls)	Index	$0.9507/gal	(0.2		)
July 2016 - June 2017	Natural Gas	7,082	(MMBtu/d)	Index	$2.8551/MMBtu*	(3.0		)
October 2016	Condensate	50	(MBbls)	Index	$40.20/bbl	(0.5		)
						$	(0.5	)

* weighted average

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, 2016, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $0.5 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas and NGL prices would result in a change of approximately $3.6 million in the net fair value of these contracts as of June 30, 2016. 

Interest Rate Risk

The Company is exposed to interest rate risk on our variable rate credit facility. At June 30, 2016, the credit facility had $15.1 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change its annual interest expense by approximately $0.2 million for the year.

The Partnership is exposed to interest rate risk on its variable rate credit facility. At June 30, 2016, the Partnership's credit facility had $697.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change its annual interest expense by approximately $7.0 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 $2,436.4 million as of June 30, 2016, based on market prices of similar debt at June 30, 2016. 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 $192.2 million decrease in fair value of the Partnership's senior unsecured notes at June 30, 2016.

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, 2016), our disclosure controls and procedures were effective to provide reasonable assurance that information

53

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, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

54

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.

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, 2015.

55

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**	—	TOM-STACK Securities Purchase Agreement, dated as of December 6, 2015, among Tall Oak Midstream, LLC, FE-STACK, LLC, TOM-STACK Holdings, LLC, TOM STACK, LLC, EnLink TOM Holdings, LP and EnLink Midstream, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
2.2**	—	TOMPC Securities Purchase Agreement, dated as of December 6, 2015, among TOMPC LLC, Tall Oak Midstream, LLC, EnLink TOM Holdings, LP, and EnLink Midstream, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
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	—	Eighth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP dated January 7, 2016 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
3.11	—	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).
3.12	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, file No. 333-194465).
3.13	—	Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 2014 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014, file No. 001-36340).
3.14	—	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of January 7, 2016 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
4.1	—	Registration Rights Agreement, dated as of January 7, 2016, by and between EnLink Midstream Partners, LP and Enfield Holdings, L.P. (incorporated by reference to Exhibit 4.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016).
4.2	—	Registration Rights Agreement, dated as of January 7, 2016, by and among EnLink Midstream, LLC, Tall Oak Midstream, LLC and FE-STACK, LLC (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36336).

56

4.3	—	Indenture, dated as of March 19, 2014, by and among EnLink Midstream Partners, LP, Subsidiary Guarantors, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014, file No. 001-36340).
4.4	—	Fourth Supplemental Indenture, dated as of July 14, 2016, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 11, 2016, filed with the Commission on July 14, 2016, file No. 001-36340).
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, 2016, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2016 and 2015, (iii) Consolidated Statements of Changes in Members’ Equity for the six months ended June 30, 2016, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and 2015, 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.

57

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 3, 2016

58

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 3, 2016

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 3, 2016

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, 2016 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 3, 2016
	/s/ MICHAEL J. GARBERDING
	Michael J. Garberding
	Chief Financial Officer
August 3, 2016

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

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 22, 2016
Document Information [Line Items]
Document Type	10-Q
Document Fiscal Period Focus	Q2
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
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		180,035,410

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 10.2	$ 18.0
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	68.5	37.5
Accrued revenue and other	295.7	268.8
Related party	72.6	110.8
Fair value of derivative assets	5.3	16.8
Natural gas and NGLs inventory, prepaid expenses and other	39.6	41.8
Total current assets	491.9	493.7
Property and equipment, net of accumulated depreciation of $1,941.4 and $1,757.6, respectively	6,160.4	5,666.8
Intangible assets, net of accumulated amortization of $112.1 and $54.6, respectively	1,666.7	689.9
Goodwill	1,541.3	2,413.9
Investment in unconsolidated affiliates	299.7	274.3
Other assets, net	2.3	2.7
Total assets	10,162.3	9,541.3
Current liabilities:
Accounts payable and drafts payable	46.0	33.2
Accounts payable to related party	10.4	14.8
Accrued gas, NGLs, condensate and crude oil purchases	247.3	206.7
Fair value of derivative liabilities	5.8	2.9
Installment payable, net of discount of $14.2	235.8	0.0
Other current liabilities	146.1	174.8
Total current liabilities	691.4	432.4
Long-term debt	3,364.1	3,066.0
Fair value of derivative liabilities	0.0	0.1
Asset retirement obligation	13.2	12.9
Other long-term liabilities	57.0	65.9
Installment payable, net of discount of $39.3	210.7	0.0
Deferred tax liability	539.1	532.1
Redeemable non-controlling interest	6.5	7.0
Members' equity (180,035,410 and 164,242,160 units issued and outstanding at June 30, 2016 and December 31, 2015, respectively)	1,970.2	2,285.7
Non-controlling interest	3,310.1	3,139.2
Total members' equity	5,280.3	5,424.9
Commitment and Contingencies (Note 15)
Total liabilities and members’ equity	$ 10,162.3	$ 9,541.3

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets [Abstract]
Allowance for bad debt	$ 0.3	$ 0.3
Property and equipment accumulated depreciation	1,941.4	1,757.6
Intangible assets accumulated amortization	112.1	54.6
Liabilities [Abstract]
Installment payable, net of discount of $14.2	14.2	0.0
Installment payable, net of discount of $39.3	$ 39.3	$ 0.0
Common unitholders	180,035,410	164,242,160

XML

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Product sales	$ 738.3	$ 956.2	$ 1,326.8	$ 1,626.9
Product sales - affiliates	31.7	31.7	56.2	47.9
Midstream services	108.3	135.9	222.8	238.3
Midstream services - affiliates	160.6	149.5	323.2	300.5
Gain (loss) on derivative activity	(5.7)	1.2	(6.1)	1.4
Total revenues	1,033.2	1,274.5	1,922.9	2,215.0
Operating costs and expenses:
Cost of sales (1)	732.4	968.2	1,318.6	1,625.6
Operating expenses (2)	100.1	109.1	198.3	207.6
General and administrative (3)	30.3	28.1	65.4	70.8
Loss on disposition of assets	0.3	0.0	0.1	0.0
Depreciation and amortization	124.9	97.7	246.8	189.0
Impairments	0.0	0.0	873.3	0.0
Total operating costs and expenses	988.0	1,203.1	2,702.5	2,093.0
Operating income (loss)	45.2	71.4	(779.6)	122.0
Other income (expense):
Interest expense, net of interest income	(46.5)	(22.6)	(90.5)	(41.7)
Income (loss) from unconsolidated affiliates	0.8	5.9	(1.6)	9.7
Other income (loss)	(0.1)	0.1	0.0	0.5
Total other expense	(45.8)	(16.6)	(92.1)	(31.5)
Income (loss) before non-controlling interest and income taxes	(0.6)	54.8	(871.7)	90.5
Income tax benefit (provision)	1.8	(10.2)	1.6	(20.9)
Net income (loss)	1.2	44.6	(870.1)	69.6
Net income (loss) attributable to the non-controlling interest	0.4	28.4	(413.3)	36.4
Net income (loss) attributable to EnLink Midstream, LLC	0.8	16.2	(456.8)	33.2
Devon investment interest in net income	0.0	1.7	0.0	2.4
EnLink Midstream, LLC interest in net income (loss)	$ 0.8	$ 14.5	$ (456.8)	$ 30.8
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit	$ 0.01	$ 0.09	$ (2.55)	$ 0.19
Diluted common unit	$ 0.01	$ 0.09	$ (2.55)	$ 0.19

XML

Condensed Consolidated Statements of Operations (parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Affiliate cost of sales	$ 732.4	$ 968.2	$ 1,318.6	$ 1,625.6
Affiliate operating expenses	100.1	109.1	198.3	207.6
Affiliate general and administrative	30.3	28.1	65.4	70.8
Affiliated Entity [Member]
Affiliate cost of sales	49.8	32.0	92.4	39.9
Affiliate operating expenses	0.2	0.2	0.3	0.2
Affiliate general and administrative	$ 0.0	$ 0.1	$ 0.0	$ 0.1

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Consolidated Statements of Changes in Members' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Units	Non-Controlling Interest
Stockholders' Equity Attributable to Parent	$ 2,285.7	$ 2,285.7
Common Stock, Shares, Outstanding		164.2
Stockholders' Equity Attributable to Noncontrolling Interest	3,139.2		$ 3,139.2
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,424.9
Increase (Decrease) in Members' Equity
Unit-based compensation	15.4	$ 7.7	7.7
Issuance of common units by the Partnership	52.3		52.3
Issuance of Preferred Units by the Partnership	724.1		724.1
Issuance of common units	214.9	$ 214.9
Issuance of common units, Shares		15.6
Conversion of restricted units for common, net of units withheld for taxes	(1.1)	$ (1.1)
Conversion of restricted units for common, net of units withheld for taxes, units		0.2
Non-controlling partner's impact of conversion of restricted units	(1.1)		(1.1)
Change in equity due to issuance of units by the Partnership	(7.5)	$ 12.5	(20.0)
Non-controlling interest distributions	(186.1)		(186.1)
Noncontrolling Interest Contributions	5.9		5.9
Distributions to members	(92.7)	(92.7)
Contributions from Devon to the Partnership	1.4		1.4
Net loss	(870.1)	(456.8)	(413.3)
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Dec. 31, 2015	7.0
Increase (Decrease) in Temporary Equity
Redeemable Noncontrolling Interest Reclassifications Between Permanent And Temporary Equity	(0.5)
Redeemable Noncontrolling Interest, Equity, Carrying Amount at Jun. 30, 2016	6.5
Stockholders' Equity Attributable to Parent	1,970.2	$ 1,970.2
Common Stock, Shares, Outstanding		180.0
Stockholders' Equity Attributable to Noncontrolling Interest	3,310.1		$ 3,310.1
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 5,280.3

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Statement of Cash Flows [Abstract]
Net income (loss)	$ (870.1)	$ 69.6
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	873.3	0.0
Depreciation and amortization	246.8	189.0
Accretion expense	0.2	0.3
Loss on disposition of assets	0.1	0.0
Deferred tax (benefit) expense	(0.6)	17.8
Non-cash unit-based compensation	15.4	21.5
(Gain) loss on derivatives recognized in net income (loss)	6.1	(5.0)
Cash settlements on derivatives	8.3	11.3
Amortization of debt issue costs	1.9	1.5
Amortization of net (premium) discount on notes	24.3	(1.5)
Redeemable non-controlling interest expense	0.3	(3.3)
Distribution of earnings from unconsolidated affiliates	0.0	10.3
(Income) loss from unconsolidated affiliates	1.6	(9.7)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other	(18.4)	57.3
Natural gas and NGLs inventory, prepaid expenses and other	12.1	(26.6)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	2.9	(55.5)
Net cash provided by operating activities	304.2	277.0
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(288.2)	(349.2)
Acquisition of business, net of cash acquired	(791.3)	(324.8)
Proceeds from sale of property	0.8	0.1
Investment in unconsolidated affiliates	(41.8)	0.0
Distribution from unconsolidated affiliates in excess of earnings	14.8	8.9
Net cash used in investing activities	(1,105.7)	(665.0)
Cash flows from financing activities:
Proceeds from borrowings	847.1	2,327.4
Payments on borrowings	(549.1)	(1,521.2)
Payments on capital lease obligations	(2.1)	(1.6)
Decrease in drafts payable	0.0	(12.4)
Debt financing costs	(0.4)	(9.5)
Mandatorily redeemable non-controlling interest	(4.0)	0.0
Conversion of restricted units, net of units withheld for taxes	(1.1)	(2.8)
Conversion of Partnership's restricted units, net of units withheld for taxes	(1.1)	(2.5)
Proceeds from issuance of Partnership's common units	52.3	4.1
Distributions to non-controlling partners	(186.6)	(175.7)
Distribution to Members	(92.7)	(79.3)
Contributions from Devon	1.4	28.8
Distributions to Devon for net assets acquired	0.0	(171.0)
Proceeds from issuance of Partnership Preferred Units	724.1	0.0
Contributions by non-controlling interest	5.9	7.3
Net cash provided by financing activities	793.7	391.6
Net increase (decrease) in cash and cash equivalents	(7.8)	3.6
Cash and cash equivalents, beginning of period	18.0	68.4
Cash and cash equivalents, end of period	10.2	72.0
Cash paid for interest	67.8	44.4
Cash paid (refund) for income taxes	$ (5.8)	$ 13.4

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Organization and Summary of Significant Agreement

6 Months Ended

Jun. 30, 2016

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 EnLink Oklahoma Gas Processing, LP (formerly known as EnLink TOM Holdings, LP) and its consolidated subsidiaries (collectively, “EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.

(a)Organization of Business

EnLink Midstream, LLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

Our assets consist of equity interests in the Partnership and EnLink Oklahoma T.O. 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. EnLink Oklahoma T.O. is a partnership held by us and the Partnership and is engaged in the gathering and processing of natural gas. As of June 30, 2016, our interests in the Partnership and EnLink Oklahoma T.O. consist of the following:

• 88,528,451 common units representing an aggregate 23.0% limited partner interest in the Partnership;

• 100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

• 16% limited partner interest in EnLink Oklahoma T.O.

(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. The Partnership connects the wells of producers in its market areas to its gathering systems, processes natural gas to remove NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Partnership provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership also has crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. The Partnership's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to its fractionators in south Louisiana. The Partnership's crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. The Partnership's processing plants remove NGLs and 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.

(c) Consolidation of the Partnership

In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU 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.  Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC, including the consideration of the Incentive Distribution Rights, is considered the primary beneficiary as it has the power to direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership.

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Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

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.

During the first half of 2015, the Partnership acquired assets from Devon through drop down transactions. Due to our control of the Partnership through our ownership and control of the General Partner and Devon's control of us through its ownership of our managing member, 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 condensed 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) Recent Accounting Pronouncements

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which will update ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2016-12 has the same effective date and transition requirements as ASU 2014-09, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our condensed consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

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 Partnership'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.

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Acquisitions

6 Months Ended

Jun. 30, 2016

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

Acquisition

(3) Acquisitions

Matador Acquisition

On October 1, 2015, the Partnership acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million. The transaction was accounted for using the acquisition method.

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

Purchase Price Allocation (in millions):
Assets acquired:
Current assets	$	1.1
Property, plant and equipment	35.5
Intangibles	98.8
Goodwill	9.8
Liabilities assumed:
Current liabilities	(3.9		)
Total identifiable net assets	$	141.3

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership's Texas segment and is non-deductible for tax purposes.

Deadwood Acquisition

Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, the Partnership acquired Apache's 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property, plant and equipment. The final working capital settlement paid to Apache was approximately $1.5 million. The transaction was accounted for using the acquisition method.

Tall Oak Acquisition

On January 7, 2016, we and the Partnership acquired a 16% and 84% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by the Partnership no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The Partnership's installment payables are valued net of discount within the total purchase price.

The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $784.2 million in cash paid by the Partnership, the majority of which was derived from the proceeds from the issuance of Preferred Units, and (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by us and approximately $22.2 million in cash paid by us. The transaction was accounted for using the acquisition method.

The following table presents the consideration we paid and 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.

Consideration (in millions):
Cash	$	806.4
Issuance of common units	214.9
The Partnership's total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018	420.9
Total consideration	$	1,442.2
Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $12.8 million in cash)	$	23.0
Property, plant and equipment	423.2
Intangibles	1,034.3
Liabilities assumed:
Current liabilities	(38.3		)
Total identifiable net assets	$	1,442.2

The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years.

We incurred $3.7 million of direct transaction costs for the six months ended June 30, 2016. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 7, 2016 to June 30, 2016, we recognized $72.2 million of revenues and $23.5 million of net loss related to the assets acquired.

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. 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 acquisitions is reflected below.

	Three Months Ended    June 30,		Six Months Ended   June 30,
	2015		2015
	(in millions)
Pro forma total revenues	$	1,283.3	$	2,350.9
Pro forma net income	$	27.7	$	31.5
Pro forma net income attributable to EnLink Midstream, LLC	$	12.2	$	22.8
Pro forma net income per common unit:
Basic	$	0.07	$	0.13
Diluted	$	0.07	$	0.13

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Goodwill and Intangible Assets

6 Months Ended

Jun. 30, 2016

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. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During February 2016, we determined that continued further weakness in the overall energy sector driven by low commodity prices together with a further decline in our unit price and the Partnership's unit price subsequent to year-end caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units.

We and the Partnership perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments for the Texas and Crude and Condensate reporting units. We use a market approach to perform the assessment for our Corporate reporting unit. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, control premium and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors.

The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. Using the fair value approaches described above, in step one of the goodwill impairment test, we and the Partnership determined that the estimated fair values of the Partnership's Texas and Crude and Condensate reporting units and our Corporate reporting unit were less than their respective carrying amounts. At the Partnership's Texas and Crude and Condensate reporting units, this is primarily related to increases in the discount rate subsequent to year-end. For our Corporate reporting unit, this is primarily due to a further decline in our unit price subsequent to year-end. The second step of the goodwill impairment test at the Partnership measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized for the three months ended March 31, 2016, which is included in the six months ended June 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.

We and the Partnership concluded that the fair value of goodwill of the Oklahoma reporting unit exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with this remaining reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

Our and the Partnership's respective impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our and the Partnership's assumptions and estimates, or assumptions and estimates change due to new information, we and the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The estimated fair values of our Corporate reporting unit and the Partnership's Texas reporting unit may be impacted in the future by a further decline in our unit price or the Partnership's unit price or a continuing prolonged period of lower commodity prices which may adversely affect the Partnership's estimate of future cash flows all of which could result in future goodwill impairment charges.

The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):

	Texas			Louisiana		Oklahoma		Crude and Condensate			Corporate			Totals
Six Months Ended June 30, 2016
Balance, beginning of period	$	703.5		$	—	$	190.3	$	93.2		$	1,426.9		$	2,413.9
Impairment	(473.1		)	—		—		(93.2		)	(307.0		)	(873.3		)
Acquisition adjustment	0.7			—		—		—			—			0.7
Balance, end of period	$	231.1		$	—	$	190.3	$	—		$	1,119.9		$	1,541.3

Intangible Assets

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

The following table represents the Partnership's change in carrying value of intangible assets (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Six Months Ended June 30, 2016
Customer relationships, beginning of period	$	744.5	$	(54.6	)	$	689.9
Acquisitions	1,034.3		—			1,034.3
Amortization expense	—		(57.5		)	(57.5		)
Customer relationships, end of period	$	1,778.8	$	(112.1	)	$	1,666.7

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $30.0 million and $18.2 million for the three months ended June 30, 2016 and 2015, respectively, and $57.5 million and $29.7 million for the six months ended June 30, 2016 and 2015, respectively.

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

2016 (remaining)	$	58.4
2017	116.7
2018	116.7
2019	116.7
2020	116.7
Thereafter	1,141.5
Total	$	1,666.7

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Affiliate Transactions

6 Months Ended

Jun. 30, 2016

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, 2016 and 2015, Devon was a significant customer to the Partnership. Devon accounted for 18.6% and 19.7% of the Partnership's revenues for the three and six months ended June 30, 2016, respectively, and 14.2% and 15.7% for the three and six months ended June 30, 2015, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $72.6 million as of June 30, 2016 and $110.8 million as of December 31, 2015. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $10.4 million as of June 30, 2016 and $14.8 million as of December 31, 2015. 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.

EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

In January 2016, in connection with the Tall Oak acquisition, we acquired a Gas Gathering and Processing Agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has a minimum volume commitment that will remain in place during each calendar quarter for the next five years and a remaining overall term of approximately 13 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC 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 DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. EnLink Oklahoma T.O. will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

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Long-Term Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

(6) Long-Term Debt

As of June 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):

	June 30, 2016			December 31, 2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively	$	697.0		$	414.0
Company credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at June 30, 2016 was 4.25%	15.1			—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.3 million at June 30, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%	399.7			399.6
The Partnership's senior unsecured notes (due 2022), including a premium of $17.5 million at June 30, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%	180.0			181.4
The Partnership's senior unsecured notes (due 2024), net of premium of $2.7 million at June 30, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%	552.7			552.9
The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at June 30, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%	748.8			748.8
The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at June 30, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%	349.8			349.8
The Partnership's senior unsecured notes (due 2045), net of discount of $6.8 million at June 30, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%	443.2			443.1
Debt issuance cost, net of amortization of $7.0 million at June 30, 2016 and $5.1 million at December 31, 2015.	(22.2		)	(23.8		)
Other debt	—			0.2
Debt classified as long-term	$	3,364.1		$	3,066.0

Company Credit Facility

The Company has 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) 88,528,451 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (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 0.5%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing the credit facility could be foreclosed upon.

As of June 30, 2016 there was $15.1 million in outstanding borrowings under the credit facility, leaving approximately $234.9 million available for future borrowing based on the borrowing capacity of $250.0 million. The Company expect to be in compliance with all credit facility covenants for at least the next twelve months.

Partnership Credit Facility

The Partnership has a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”) that matures on March 6, 2020. Under the Partnership credit facility, 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 $500.0 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year on each occasion. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the 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, 2016, there were $11.1 million in outstanding letters of credit and $697.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $791.9 million available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms and conditions 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, 2015. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

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Income Tax

6 Months Ended

Jun. 30, 2016

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,
	2016			2015		2016			2015
	(in millions)
ENLC income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income before income taxes:

	Three Months Ended    June 30,					Six Months Ended   June 30,
	2016			2015		2016			2015
	(in millions)
Tax expense (benefit) at statutory federal rate (35%)	$	0.5		$	8.4	$	(160.0	)	$	17.4
State income taxes expense (benefit), net of federal tax benefit	—			0.6		(14.9		)	1.2
Income tax expense (benefit) from partnership	(2.3		)	0.7		(1.3		)	1.9
Non-deductible expense related to asset impairment	—			—		173.9			—
Other	—			0.5		0.7			0.4
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

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Certain Provision of the Partnership Agreement

6 Months Ended

Jun. 30, 2016

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, 2016, the Partnership sold an aggregate of 3.3 million common units under the BMO EDA, generating proceeds of approximately $52.3 million (net of approximately $0.5 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of June 30, 2016, approximately $264.4 million remains available to be issued under the BMO EDA.

(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. The Class C Common Units were substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units converted into common units on a one-for-one basis on May 13, 2016.

(c) Preferred Units

In January 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (“Preferred Units”) representing the Partnership's limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund the Partnership's portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into the Partnership's common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership's option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the General Partner or our managing member, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. A distribution on the Preferred Units for the three months ended March 31, 2016, was paid-in kind through the issuance of 992,445 Preferred Units on May 12, 2016. A distribution on the Preferred Units was declared for the three months ended June 30, 2016, which will result in the issuance of 1,083,589 additional Preferred Units on August 11, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the three and six months ended June 30, 2016, $18.0 million and $29.8 million of income was allocated to the Preferred Units, respectively.

(d)  Distributions

Unless restricted by the terms of the Partnership 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 Preferred 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, 2016 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2015	$	0.39	February 11, 2016
First Quarter of 2016	$	0.39	May 12, 2016
Second Quarter of 2016	$	0.39	August 11, 2016

(e) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in (d) above. 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, 2016 and 2015 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Income allocation for incentive distributions	$	14.2		$	11.3		$	28.0		$	20.1
Unit-based compensation attributable to ENLC’s restricted units	(3.6		)	(3.9		)	(7.6		)	(10.9		)
General Partner share of net income (loss)	—			0.2			(2.4		)	0.3
General Partner interest in drop down transactions	—			11.5			—			36.1
General Partner interest in net income	$	10.6		$	19.1		$	18.0		$	45.6

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Earnings per Unit and Dilution Computations

6 Months Ended

Jun. 30, 2016

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 (loss) attributable to the drop down interests acquired during 2015 from Devon for periods prior to acquisition is not allocated for purposes of calculating net income (loss) per common unit as they were fully assigned to the general partner interest. The following table reflects the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2016 and 2015 (in millions, except per unit amounts):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
EnLink Midstream, LLC interest in net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Distributed earnings allocated to:
Common units (1) (2)	$	45.9		$	41.1		$	91.5		$	81.3
Unvested restricted units (1) (2)	0.5			0.3			1.0			0.5
Total distributed earnings	$	46.4		$	41.4		$	92.5		$	81.8
Undistributed loss allocated to:
Common units	$	(44.7	)	$	(26.7	)	$	(543.2	)	$	(50.7	)
Unvested restricted units	(0.9		)	(0.2		)	(6.1		)	(0.3		)
Total undistributed loss	$	(45.6	)	$	(26.9	)	$	(549.3	)	$	(51.0	)
Net income (loss) allocated to:
Common units	$	1.2		$	14.4		$	(451.7	)	$	30.6
Unvested restricted units	(0.4		)	0.1			(5.1		)	0.2
Total net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Basic and diluted net income (loss) per unit:
Basic	$	0.01		$	0.09		$	(2.55	)	$	0.19
Diluted	$	0.01		$	0.09		$	(2.55	)	$	0.19

(1) Three months ended June 30, 2016 and 2015 represents a declared distribution of $0.255 per unit payable August 12, 2016 and a distribution of $0.25 per unit paid on August 14, 2015, respectively.

(2) Six months ended June 30, 2016 and 2015 represents a distribution of $0.255 per unit paid on May 13, 2016, a declared distribution of $0.255 per unit payable on August 12, 2016 and distributions of $0.245 per unit paid on May 15, 2015 and of $0.25 per unit paid on August 14, 2015.

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,
	2016	2015	2016	2015
Basic and diluted earnings per unit:
Weighted average common units outstanding	180.0	164.2	179.4	164.2
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	180.0	164.2	179.4	164.2
Dilutive effect of restricted units issued	0.8	0.4	—	0.4
Total weighted average diluted common units outstanding	180.8	164.6	179.4	164.6

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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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2016

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:

	Six Months Ended   June 30,
	2016			2015
	(in millions)
Beginning asset retirement obligations	$	14.0		$	20.6
Revisions to existing liabilities	(0.4		)	(4.0		)
Accretion	0.2			0.3
Liabilities settled	(0.6		)	(3.2		)
Ending asset retirement obligations	$	13.2		$	13.7

There are no asset retirement obligations included in Other Current Liabilities as of June 30, 2016. Asset retirement obligations of $1.1 million are included in Other Current Liabilities as of December 31, 2015.

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Investment in Unconsolidated Affiliate

6 Months Ended

Jun. 30, 2016

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 Gulf Coast Fractionators (“GCF”) at June 30, 2016 and 2015 and approximately 31.0% ownership interest in Howard Energy Partners (“HEP”) at June 30, 2016 and 2015.

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, 2016
Contributions	$	—		$	34.7		$	34.7
Distributions	$	0.5		$	5.1		$	5.6
Equity in net income	$	0.5		$	0.3		$	0.8
June 30, 2015
Distributions	$	4.2		$	8.2		$	12.4
Equity in net income	$	2.9		$	3.0		$	5.9
Six months ended
June 30, 2016
Contributions	$	—		$	41.8		$	41.8
Distributions	$	3.5		$	11.3		$	14.8
Equity in net loss	$	(1.2	)	$	(0.4	)	$	(1.6	)
June 30, 2015
Distributions	$	6.9		$	12.3		$	19.2
Equity in net income	$	6.3		$	3.4		$	9.7

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

	June 30, 2016		December 31, 2015
Gulf Coast Fractionators	$	47.9	$	52.6
Howard Energy Partners	251.8		221.7
Total investment in unconsolidated affiliates	$	299.7	$	274.3

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Employee Incentive Plans

6 Months Ended

Jun. 30, 2016

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 condensed consolidated financial statements. On April 7, 2016, the General Partner amended and restated the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). Amendments to the GP Plan included an increase to the number of the Partnership's common units authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes.

The Partnership and we 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 is recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and EnLink Oklahoma T.O. 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,
	2016		2015		2016		2015
Cost of unit-based compensation charged to general and administrative expense	$	5.7	$	6.6	$	12.0	$	18.5
Cost of unit-based compensation charged to operating expense	1.7		1.1		3.4		3.0
Total amount charged to income	$	7.4	$	7.7	$	15.4	$	21.5
Interest of non-controlling partners in unit-based compensation	$	2.7	$	3.7	$	5.6	$	9.2
Amount of related income tax benefit recognized in income	$	1.8	$	1.5	$	3.7	$	4.6

(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, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,253,729			$	29.59
Granted	1,046,685			10.03
Vested*	(297,439		)	30.33
Forfeited	(40,998		)	22.17
Non-vested, end of period	1,961,977			$	19.20
Aggregate intrinsic value, end of period (in millions)	$	32.6

* Vested units include 85,366 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2016 and 2015, respectively, is provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	0.1	$	0.4	$	3.8	$	7.2
Fair value of units vested	$	—	$	0.5	$	9.0	$	7.5

As of June 30, 2016, there was $19.0 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 1.8 years.

(c)EnLink Midstream Partners, LP Performance Units

In 2016, the General Partner and the managing member of ENLC granted performance awards under the GP Plan and the EnLink Midstream, LLC 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 (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership's common units and the designated peer group securities; (iii) an estimated ranking of the Partnership among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of 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:	January 2016			February 2016
Beginning TSR Price	$	14.82		$	14.82
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	39.71		%	42.33		%
Distribution yield	12.10		%	19.20		%

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

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	118,126			$	35.41
Granted	258,078			9.81
Forfeited	(2,798		)	36.18
Non-vested, end of period	373,406			$	17.71
Aggregate intrinsic value, end of period (in millions)	$	6.2

As of June 30, 2016 there was $4.4 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 2.0 years.

(d)EnLink Midstream, LLC Restricted Incentive Units

ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the six months endedJune 30, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,148,893			$	34.78
Granted	1,038,619			9.44
Vested*	(320,497		)	36.92
Forfeited	(37,952		)	23.95
Non-vested, end of period	1,829,063			$	20.24
Aggregate intrinsic value, end of period (in millions)	$	29.1

* Vested units include 91,256 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2016 and 2015, respectively, are provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	0.6	$	3.8	$	8.9
Fair value of units vested	$	—	$	0.6	$	11.8	$	9.2

As of June 30, 2016, there was $18.6 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 1.7 years.

(e) EnLink Midstream, LLC's Performance Units

In 2016, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC's common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the 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:	January 2016			February 2016
Beginning TSR Price	$	15.38		$	15.38
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	46.02		%	52.05		%
Distribution yield	8.60		%	14.00		%

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

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	105,080			$	40.50
Granted	242,646			9.59
Forfeited	(2,525		)	41.31
Non-vested, end of period	345,201			$	18.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

As of June 30, 2016, there was $4.2 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 2.0 years.

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Derivatives

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(13)Derivatives

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 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Change in fair value of derivatives	$	(8.4	)	$	(2.5	)	$	(14.4	)	$	(6.3	)
Realized gain on derivatives	2.7			3.7			8.3			7.7
Gain (loss) on derivative activity	$	(5.7	)	$	1.2		$	(6.1	)	$	1.4

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

	June 30, 2016			December 31, 2015
Fair value of derivative assets — current	$	5.3		$	16.8
Fair value of derivative liabilities — current	(5.8		)	(2.9		)
Fair value of derivative liabilities — long term	—			(0.1		)
Net fair value of derivatives	$	(0.5	)	$	13.8

Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity in the Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The total estimated fair value liability of derivative contracts of $0.5 million as of June 30, 2016 has a maturity date of less than one year.

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, 2016. The remaining term of the contracts extend no later than June 2017.

			June 30, 2016
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(31.9	)	$	3.4
NGL (long contracts)	Swaps	Gallons	11.4		(0.4		)
Natural Gas (short contracts)	Swaps	MMBtu	(6.3	)	(2.9		)
Natural Gas (long contracts)	Swaps	MMBtu	1.3		(0.1		)
Condensate (short contracts)	Swaps	MMBbls	(0.1	)	(0.5		)
Total fair value of derivatives					$	(0.5	)

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, 2016 of $5.3 million would be eliminated due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. 

Interest Rate Swaps

The Partnership entered into interest rate swaps during April and May 2015 in connection with the issuance of the 2025 Notes in May 2015. The Partnership did not enter into any interest rate swaps for the six months ended June 30, 2016.

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

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2016		2015		2016		2015
Settlement gains on derivatives	$	—	$	3.6	$	—	$	3.6

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Fair Value Measurements

6 Months Ended

Jun. 30, 2016

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

	June 30, 2016 Level 2			December 31, 2015 Level 2
Commodity Swaps*	$	(0.5	)	$	13.8
Total	$	(0.5	)	$	13.8

* 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 the Partnership's and/or the counterparty credit risk of the Partnership as required under FASB ASC 820.

Fair Value of Financial Instruments

The Partnership has determined the estimated fair value of its financial instruments 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, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	3,364.1	$	3,148.5	$	3,066.0	$	2,585.5
Installment Payables	$	446.5	$	451.6	$	—	$	—
Obligations under capital leases	$	12.3	$	11.5	$	16.7	$	15.6

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 $697.0 million and $414.0 million in outstanding borrowings under its revolving credit facility as of June 30, 2016 and December 31, 2015, respectively. We had $15.1 million in outstanding borrowings under our credit facility as of June 30, 2016. As borrowings under either credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the applicable credit facility. As of June 30, 2016 and December 31, 2015, the Partnership had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes and installment payables as of June 30, 2016 and December 31, 2015 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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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

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 EnLink Midstream Operating, LP. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or its affiliates or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.

(b) Environmental Issues

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting 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. In February 2016, a spill occurred at the Partnership's Kill Buck Station in the Ohio operations.  State and federal agencies were notified and clean-up response efforts were promptly executed, which significantly lessened the impact of the spill.  On April 7, 2016, the state agency determined that the clean-up recovery efforts were completed and has internally transitioned monitoring to their water quality division.  The Partnership does not anticipate a material fine or penalty by either the state or federal agencies.  Additionally, although the spill that previously occurred in the Partnership's West Virginia operations in the third quarter of 2015 is still pending, the Partnership does not believe that any fine or penalty that may be issued will be material to its operations.  Lastly, the Partnership continues to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

(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, from time to time the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and any 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 effect on its financial position, results of operations or cash flows. 

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed, owned or operated 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 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, resulting in damage to certain of the Partnership's facilities. 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 has also sued 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.

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Segment Information

6 Months Ended

Jun. 30, 2016

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”). 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 unconsolidated affiliate 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, 2016
Product sales	$	41.9		$	399.5		$	8.9		$	288.0		$	—		$	738.3
Product sales-affiliates	72.7			15.2			22.5			0.9			(79.6		)	31.7
Midstream services	23.2			52.7			18.0			14.4			—			108.3
Midstream services-affiliates	111.9			25.5			41.7			4.0			(22.5		)	160.6
Cost of sales	(103.6		)	(425.5		)	(31.6		)	(273.8		)	102.1			(732.4		)
Operating expenses	(43.0		)	(25.4		)	(11.8		)	(19.9		)	—			(100.1		)
Loss on derivative activity	—			—			—			—			(5.7		)	(5.7		)
Segment profit	$	103.1		$	42.0		$	47.7		$	13.6		$	(5.7	)	$	200.7
Depreciation and amortization	$	(48.7	)	$	(28.6	)	$	(34.8	)	$	(10.6	)	$	(2.2	)	$	(124.9	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	57.2		$	14.1		$	63.1		$	0.9		$	4.9		$	140.2
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
Six Months Ended June 30, 2016
Product sales	$	104.4		$	687.2		$	16.7		$	518.5		$	—		$	1,326.8
Product sales-affiliates	110.0			22.6			33.1			1.1			(110.6		)	56.2
Midstream services	50.6			107.9			33.1			31.2			—			222.8
Midstream services-affiliates	222.2			38.2			86.7			9.2			(33.1		)	323.2
Cost of sales	(194.9		)	(727.6		)	(50.9		)	(488.9		)	143.7			(1,318.6		)
Operating expenses	(82.3		)	(48.7		)	(24.6		)	(42.7		)	—			(198.3		)
Loss on derivative activity	—			—			—			—			(6.1		)	(6.1		)
Segment profit	$	210.0		$	79.6		$	94.1		$	28.4		$	(6.1	)	$	406.0
Depreciation and amortization	$	(94.9	)	$	(57.9	)	$	(68.6	)	$	(21.0	)	$	(4.4	)	$	(246.8	)

Impairments	$	(473.1	)	$	—		$	—		$	(93.2	)	$	(307.0	)	$	(873.3	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	80.5		$	36.8		$	132.3		$	4.2		$	6.8		$	260.6
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

The table below presents information about segment assets as of June 30, 2016 and December 31, 2015:

	June 30, 2016		December 31, 2015
Segment Identifiable Assets:	(In millions)
Texas	$	3,179.9	$	3,709.5
Louisiana	2,330.9		2,309.3
Oklahoma	2,413.6		873.4
Crude and Condensate	780.6		898.0
Corporate	1,457.3		1,751.1
Total identifiable assets	$	10,162.3	$	9,541.3

The following table reconciles the segment profits reported above to the operating income (loss) as reported in the Condensed Consolidated Statements of Operations (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Segment profits	$	200.7		$	197.2		$	406.0		$	381.8
General and administrative expenses	(30.3		)	(28.1		)	(65.4		)	(70.8		)
Loss on disposition of assets	(0.3		)	—			(0.1		)	—
Depreciation and amortization	(124.9		)	(97.7		)	(246.8		)	(189.0		)
Impairments	—			—			(873.3		)	—
Operating income (loss)	$	45.2		$	71.4		$	(779.6	)	$	122.0

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Elements [Abstract]

Cash Flow, Supplemental Disclosures

(17) Supplemental Cash Flow Information

The following schedule summarizes non-cash financing activities for the period presented:

	Six Months Ended   June 30,
	2016		2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	214.9	$	—
Non-cash issuance of common units of the Partnership (2)	—		180.0
Non-cash issuance of Class C Common Units of the Partnership (2)	—		180.0
Installment payable, net of discount of $79.1 million (3)	420.9		—

(1) For the six months ended June 30, 2016, non-cash common units were issued as partial consideration for the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

(2) For the six months ended June 30, 2015, non-cash common units and Class C Common Units were issued by the Partnership as partial consideration for the Coronado acquisition.

(3) The Partnership incurred installment purchase obligations, net of discount, assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

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Other Information

6 Months Ended

Jun. 30, 2016

Other Liabilities Disclosure [Abstract]

Other Liabilities Disclosure [Text Block]

(18) Other Information

The following table presents additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following:

	June 30, 2016		December 31, 2015
	(in millions)
Accrued interest	$	23.6	$	23.2
Accrued wages and benefits, including taxes	10.3		27.7
Accrued ad valorem taxes	23.7		27.0
Capital expenditure accruals	23.6		22.3
Onerous performance obligations	16.3		17.0
Other	48.6		57.6
Other current liabilities	$	146.1	$	174.8

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Subsequent Events

6 Months Ended

Jun. 30, 2016

Subsequent Event [Line Items]

Subsequent Events [Text Block]

(19) Subsequent Events

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership's 4.850% senior notes due 2026 (the "2026 Notes") at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million will be used to repay outstanding borrowings under the Partnership's revolving credit facility and for general partnership purposes.

On August 1, 2016, the Partnership formed a joint venture with an affiliate of NGP Natural Resources XI, L.P. (“NGP”) to operate and expand its natural gas, natural gas liquids, and crude oil midstream assets in the liquids-rich Delaware Basin.  The joint venture is initially owned 50.1 percent by the Partnership and 49.9 percent by NGP. The Partnership contributed approximately $230.0 million of existing assets within the Texas segment to the joint venture and committed an additional $285.0 million in capital to fund potential future development projects and potential acquisitions. NGP committed an aggregate of approximately $400.0 million of capital, including an initial contribution of approximately $115.0 million, which the joint venture distributed to the Partnership at the formation of the joint venture to reimburse the Partnership for capital spent to date on existing assets and ongoing projects. As part of this agreement, NGP granted the Partnership graded call rights beginning in 2021 to acquire increasing portions of NGP’s interest in the joint venture at a price based upon a fixed multiple.

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

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.

During the first half of 2015, the Partnership acquired assets from Devon through drop down transactions. Due to our control of the Partnership through our ownership and control of the General Partner and Devon's control of us through its ownership of our managing member, 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 condensed 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.

New Accounting Pronouncements, Policy

(b) Recent Accounting Pronouncements

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which will update ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2016-12 has the same effective date and transition requirements as ASU 2014-09, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our condensed consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

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 Partnership'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.

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Acquisition (Table)

6 Months Ended

Jun. 30, 2016

Business Acquisition [Line Items]

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 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. 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 acquisitions is reflected below.

	Three Months Ended    June 30,		Six Months Ended   June 30,
	2015		2015
	(in millions)
Pro forma total revenues	$	1,283.3	$	2,350.9
Pro forma net income	$	27.7	$	31.5
Pro forma net income attributable to EnLink Midstream, LLC	$	12.2	$	22.8
Pro forma net income per common unit:
Basic	$	0.07	$	0.13
Diluted	$	0.07	$	0.13

Tall Oak [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the consideration we paid and 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.

Consideration (in millions):
Cash	$	806.4
Issuance of common units	214.9
The Partnership's total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018	420.9
Total consideration	$	1,442.2
Purchase Price Allocation (in millions):
Assets acquired:
Current assets (including $12.8 million in cash)	$	23.0
Property, plant and equipment	423.2
Intangibles	1,034.3
Liabilities assumed:
Current liabilities	(38.3		)
Total identifiable net assets	$	1,442.2

Matador [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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

Purchase Price Allocation (in millions):
Assets acquired:
Current assets	$	1.1
Property, plant and equipment	35.5
Intangibles	98.8
Goodwill	9.8
Liabilities assumed:
Current liabilities	(3.9		)
Total identifiable net assets	$	141.3

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Goodwill and Intangible Assets (Tables)

6 Months Ended

Jun. 30, 2016

Goodwill [Line Items]

Schedule of Goodwill

The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):

	Texas			Louisiana		Oklahoma		Crude and Condensate			Corporate			Totals
Six Months Ended June 30, 2016
Balance, beginning of period	$	703.5		$	—	$	190.3	$	93.2		$	1,426.9		$	2,413.9
Impairment	(473.1		)	—		—		(93.2		)	(307.0		)	(873.3		)
Acquisition adjustment	0.7			—		—		—			—			0.7
Balance, end of period	$	231.1		$	—	$	190.3	$	—		$	1,119.9		$	1,541.3

Schedule of Finite-Lived Intangible Assets

The following table represents the Partnership's change in carrying value of intangible assets (in millions):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Six Months Ended June 30, 2016
Customer relationships, beginning of period	$	744.5	$	(54.6	)	$	689.9
Acquisitions	1,034.3		—			1,034.3
Amortization expense	—		(57.5		)	(57.5		)
Customer relationships, end of period	$	1,778.8	$	(112.1	)	$	1,666.7

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

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

2016 (remaining)	$	58.4
2017	116.7
2018	116.7
2019	116.7
2020	116.7
Thereafter	1,141.5
Total	$	1,666.7

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Indebtedness Table

As of June 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):

	June 30, 2016			December 31, 2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively	$	697.0		$	414.0
Company credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at June 30, 2016 was 4.25%	15.1			—
The Partnership's senior unsecured notes (due 2019), net of discount of $0.3 million at June 30, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%	399.7			399.6
The Partnership's senior unsecured notes (due 2022), including a premium of $17.5 million at June 30, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%	180.0			181.4
The Partnership's senior unsecured notes (due 2024), net of premium of $2.7 million at June 30, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%	552.7			552.9
The Partnership's senior unsecured notes (due 2025), net of discount of $1.2 million at June 30, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%	748.8			748.8
The Partnership's senior unsecured notes (due 2044), net of discount of $0.2 million at June 30, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%	349.8			349.8
The Partnership's senior unsecured notes (due 2045), net of discount of $6.8 million at June 30, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%	443.2			443.1
Debt issuance cost, net of amortization of $7.0 million at June 30, 2016 and $5.1 million at December 31, 2015.	(22.2		)	(23.8		)
Other debt	—			0.2
Debt classified as long-term	$	3,364.1		$	3,066.0

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Income Tax (Tables)

6 Months Ended

Jun. 30, 2016

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,
	2016			2015		2016			2015
	(in millions)
ENLC income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income before income taxes:

	Three Months Ended    June 30,					Six Months Ended   June 30,
	2016			2015		2016			2015
	(in millions)
Tax expense (benefit) at statutory federal rate (35%)	$	0.5		$	8.4	$	(160.0	)	$	17.4
State income taxes expense (benefit), net of federal tax benefit	—			0.6		(14.9		)	1.2
Income tax expense (benefit) from partnership	(2.3		)	0.7		(1.3		)	1.9
Non-deductible expense related to asset impairment	—			—		173.9			—
Other	—			0.5		0.7			0.4
Total income tax expense (benefit)	$	(1.8	)	$	10.2	$	(1.6	)	$	20.9

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Certain Provision of the Partnership Agreement (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 is provided below:

Declaration period	Distribution/unit		Date paid/payable
Fourth Quarter of 2015	$	0.39	February 11, 2016
First Quarter of 2016	$	0.39	May 12, 2016
Second Quarter of 2016	$	0.39	August 11, 2016

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, 2016 and 2015 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Income allocation for incentive distributions	$	14.2		$	11.3		$	28.0		$	20.1
Unit-based compensation attributable to ENLC’s restricted units	(3.6		)	(3.9		)	(7.6		)	(10.9		)
General Partner share of net income (loss)	—			0.2			(2.4		)	0.3
General Partner interest in drop down transactions	—			11.5			—			36.1
General Partner interest in net income	$	10.6		$	19.1		$	18.0		$	45.6

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Earnings per Unit and Dilution Computations (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and 2015 (in millions, except per unit amounts):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
EnLink Midstream, LLC interest in net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Distributed earnings allocated to:
Common units (1) (2)	$	45.9		$	41.1		$	91.5		$	81.3
Unvested restricted units (1) (2)	0.5			0.3			1.0			0.5
Total distributed earnings	$	46.4		$	41.4		$	92.5		$	81.8
Undistributed loss allocated to:
Common units	$	(44.7	)	$	(26.7	)	$	(543.2	)	$	(50.7	)
Unvested restricted units	(0.9		)	(0.2		)	(6.1		)	(0.3		)
Total undistributed loss	$	(45.6	)	$	(26.9	)	$	(549.3	)	$	(51.0	)
Net income (loss) allocated to:
Common units	$	1.2		$	14.4		$	(451.7	)	$	30.6
Unvested restricted units	(0.4		)	0.1			(5.1		)	0.2
Total net income (loss)	$	0.8		$	14.5		$	(456.8	)	$	30.8
Basic and diluted net income (loss) per unit:
Basic	$	0.01		$	0.09		$	(2.55	)	$	0.19
Diluted	$	0.01		$	0.09		$	(2.55	)	$	0.19

(1) Three months ended June 30, 2016 and 2015 represents a declared distribution of $0.255 per unit payable August 12, 2016 and a distribution of $0.25 per unit paid on August 14, 2015, respectively.

(2) Six months ended June 30, 2016 and 2015 represents a distribution of $0.255 per unit paid on May 13, 2016, a declared distribution of $0.255 per unit payable on August 12, 2016 and distributions of $0.245 per unit paid on May 15, 2015 and of $0.25 per unit paid on August 14, 2015.

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,
	2016	2015	2016	2015
Basic and diluted earnings per unit:
Weighted average common units outstanding	180.0	164.2	179.4	164.2
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	180.0	164.2	179.4	164.2
Dilutive effect of restricted units issued	0.8	0.4	—	0.4
Total weighted average diluted common units outstanding	180.8	164.6	179.4	164.6

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Asset Retirement Obligation (Table)

6 Months Ended

Jun. 30, 2016

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:

	Six Months Ended   June 30,
	2016			2015
	(in millions)
Beginning asset retirement obligations	$	14.0		$	20.6
Revisions to existing liabilities	(0.4		)	(4.0		)
Accretion	0.2			0.3
Liabilities settled	(0.6		)	(3.2		)
Ending asset retirement obligations	$	13.2		$	13.7

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Investment in Unconsolidated Affiliate (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016
Contributions	$	—		$	34.7		$	34.7
Distributions	$	0.5		$	5.1		$	5.6
Equity in net income	$	0.5		$	0.3		$	0.8
June 30, 2015
Distributions	$	4.2		$	8.2		$	12.4
Equity in net income	$	2.9		$	3.0		$	5.9
Six months ended
June 30, 2016
Contributions	$	—		$	41.8		$	41.8
Distributions	$	3.5		$	11.3		$	14.8
Equity in net loss	$	(1.2	)	$	(0.4	)	$	(1.6	)
June 30, 2015
Distributions	$	6.9		$	12.3		$	19.2
Equity in net income	$	6.3		$	3.4		$	9.7

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

	June 30, 2016		December 31, 2015
Gulf Coast Fractionators	$	47.9	$	52.6
Howard Energy Partners	251.8		221.7
Total investment in unconsolidated affiliates	$	299.7	$	274.3

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Employee Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2016

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

Schedule of Share-based Compensation Arrangements by Share-based Payment Award

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:	January 2016			February 2016
Beginning TSR Price	$	15.38		$	15.38
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	46.02		%	52.05		%
Distribution yield	8.60		%	14.00		%

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:	January 2016			February 2016
Beginning TSR Price	$	14.82		$	14.82
Risk-free interest rate	1.10		%	0.89		%
Volatility factor	39.71		%	42.33		%
Distribution yield	12.10		%	19.20		%

Schedule of Nonvested Performance-based Units Activity

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

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	118,126			$	35.41
Granted	258,078			9.81
Forfeited	(2,798		)	36.18
Non-vested, end of period	373,406			$	17.71
Aggregate intrinsic value, end of period (in millions)	$	6.2

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

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	105,080			$	40.50
Granted	242,646			9.59
Forfeited	(2,525		)	41.31
Non-vested, end of period	345,201			$	18.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

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

The Partnership and we 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 is recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and EnLink Oklahoma T.O. 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,
	2016		2015		2016		2015
Cost of unit-based compensation charged to general and administrative expense	$	5.7	$	6.6	$	12.0	$	18.5
Cost of unit-based compensation charged to operating expense	1.7		1.1		3.4		3.0
Total amount charged to income	$	7.4	$	7.7	$	15.4	$	21.5
Interest of non-controlling partners in unit-based compensation	$	2.7	$	3.7	$	5.6	$	9.2
Amount of related income tax benefit recognized in income	$	1.8	$	1.5	$	3.7	$	4.6

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, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date  Fair Value
Non-vested, beginning of period	1,253,729			$	29.59
Granted	1,046,685			10.03
Vested*	(297,439		)	30.33
Forfeited	(40,998		)	22.17
Non-vested, end of period	1,961,977			$	19.20
Aggregate intrinsic value, end of period (in millions)	$	32.6

* Vested units include 85,366 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive unit activity for the six months endedJune 30, 2016 is provided below:

	Six Months Ended   June 30, 2016
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,148,893			$	34.78
Granted	1,038,619			9.44
Vested*	(320,497		)	36.92
Forfeited	(37,952		)	23.95
Non-vested, end of period	1,829,063			$	20.24
Aggregate intrinsic value, end of period (in millions)	$	29.1

* Vested units include 91,256 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, 2016 and 2015, respectively, are provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream, LLC Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	0.6	$	3.8	$	8.9
Fair value of units vested	$	—	$	0.6	$	11.8	$	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, 2016 and 2015, respectively, is provided below (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	0.1	$	0.4	$	3.8	$	7.2
Fair value of units vested	$	—	$	0.5	$	9.0	$	7.5

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2016

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 Statement of Operations as part of interest expense, net, as follows (in millions):

	Three Months Ended    June 30,				Six Months Ended   June 30,
	2016		2015		2016		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 (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Change in fair value of derivatives	$	(8.4	)	$	(2.5	)	$	(14.4	)	$	(6.3	)
Realized gain on derivatives	2.7			3.7			8.3			7.7
Gain (loss) on derivative activity	$	(5.7	)	$	1.2		$	(6.1	)	$	1.4

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, 2016			December 31, 2015
Fair value of derivative assets — current	$	5.3		$	16.8
Fair value of derivative liabilities — current	(5.8		)	(2.9		)
Fair value of derivative liabilities — long term	—			(0.1		)
Net fair value of derivatives	$	(0.5	)	$	13.8

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, 2016. The remaining term of the contracts extend no later than June 2017.

			June 30, 2016
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(31.9	)	$	3.4
NGL (long contracts)	Swaps	Gallons	11.4		(0.4		)
Natural Gas (short contracts)	Swaps	MMBtu	(6.3	)	(2.9		)
Natural Gas (long contracts)	Swaps	MMBtu	1.3		(0.1		)
Condensate (short contracts)	Swaps	MMBbls	(0.1	)	(0.5		)
Total fair value of derivatives					$	(0.5	)

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Derivative Instrument

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

	June 30, 2016 Level 2			December 31, 2015 Level 2
Commodity Swaps*	$	(0.5	)	$	13.8
Total	$	(0.5	)	$	13.8

* 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 the Partnership's and/or the counterparty credit risk of the Partnership as required under FASB ASC 820.

Fair Value Financial Instrument

The Partnership has determined the estimated fair value of its financial instruments 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, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	3,364.1	$	3,148.5	$	3,066.0	$	2,585.5
Installment Payables	$	446.5	$	451.6	$	—	$	—
Obligations under capital leases	$	12.3	$	11.5	$	16.7	$	15.6

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016
Product sales	$	41.9		$	399.5		$	8.9		$	288.0		$	—		$	738.3
Product sales-affiliates	72.7			15.2			22.5			0.9			(79.6		)	31.7
Midstream services	23.2			52.7			18.0			14.4			—			108.3
Midstream services-affiliates	111.9			25.5			41.7			4.0			(22.5		)	160.6
Cost of sales	(103.6		)	(425.5		)	(31.6		)	(273.8		)	102.1			(732.4		)
Operating expenses	(43.0		)	(25.4		)	(11.8		)	(19.9		)	—			(100.1		)
Loss on derivative activity	—			—			—			—			(5.7		)	(5.7		)
Segment profit	$	103.1		$	42.0		$	47.7		$	13.6		$	(5.7	)	$	200.7
Depreciation and amortization	$	(48.7	)	$	(28.6	)	$	(34.8	)	$	(10.6	)	$	(2.2	)	$	(124.9	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	57.2		$	14.1		$	63.1		$	0.9		$	4.9		$	140.2
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
Six Months Ended June 30, 2016
Product sales	$	104.4		$	687.2		$	16.7		$	518.5		$	—		$	1,326.8
Product sales-affiliates	110.0			22.6			33.1			1.1			(110.6		)	56.2
Midstream services	50.6			107.9			33.1			31.2			—			222.8
Midstream services-affiliates	222.2			38.2			86.7			9.2			(33.1		)	323.2
Cost of sales	(194.9		)	(727.6		)	(50.9		)	(488.9		)	143.7			(1,318.6		)
Operating expenses	(82.3		)	(48.7		)	(24.6		)	(42.7		)	—			(198.3		)
Loss on derivative activity	—			—			—			—			(6.1		)	(6.1		)
Segment profit	$	210.0		$	79.6		$	94.1		$	28.4		$	(6.1	)	$	406.0
Depreciation and amortization	$	(94.9	)	$	(57.9	)	$	(68.6	)	$	(21.0	)	$	(4.4	)	$	(246.8	)

Impairments	$	(473.1	)	$	—		$	—		$	(93.2	)	$	(307.0	)	$	(873.3	)
Goodwill	$	231.1		$	—		$	190.3		$	—		$	1,119.9		$	1,541.3
Capital expenditures	$	80.5		$	36.8		$	132.3		$	4.2		$	6.8		$	260.6
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

Segment Table Reconciliation to Condensed Consolidated Financial Statement

The table below presents information about segment assets as of June 30, 2016 and December 31, 2015:

	June 30, 2016		December 31, 2015
Segment Identifiable Assets:	(In millions)
Texas	$	3,179.9	$	3,709.5
Louisiana	2,330.9		2,309.3
Oklahoma	2,413.6		873.4
Crude and Condensate	780.6		898.0
Corporate	1,457.3		1,751.1
Total identifiable assets	$	10,162.3	$	9,541.3

Reconciliation of Operating Profit (Loss) from Segments to Consolidated

The following table reconciles the segment profits reported above to the operating income (loss) as reported in the Condensed Consolidated Statements of Operations (in millions):

	Three Months Ended    June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
Segment profits	$	200.7		$	197.2		$	406.0		$	381.8
General and administrative expenses	(30.3		)	(28.1		)	(65.4		)	(70.8		)
Loss on disposition of assets	(0.3		)	—			(0.1		)	—
Depreciation and amortization	(124.9		)	(97.7		)	(246.8		)	(189.0		)
Impairments	—			—			(873.3		)	—
Operating income (loss)	$	45.2		$	71.4		$	(779.6	)	$	122.0

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following schedule summarizes non-cash financing activities for the period presented:

	Six Months Ended   June 30,
	2016		2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	214.9	$	—
Non-cash issuance of common units of the Partnership (2)	—		180.0
Non-cash issuance of Class C Common Units of the Partnership (2)	—		180.0
Installment payable, net of discount of $79.1 million (3)	420.9		—

(1) For the six months ended June 30, 2016, non-cash common units were issued as partial consideration for the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

(2) For the six months ended June 30, 2015, non-cash common units and Class C Common Units were issued by the Partnership as partial consideration for the Coronado acquisition.

(3) The Partnership incurred installment purchase obligations, net of discount, assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.

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Other Information (Tables)

6 Months Ended

Jun. 30, 2016

Other Liabilities Disclosure [Abstract]

Other Current Liabilities [Table Text Block]

Other current liabilities consisted of the following:

	June 30, 2016		December 31, 2015
	(in millions)
Accrued interest	$	23.6	$	23.2
Accrued wages and benefits, including taxes	10.3		27.7
Accrued ad valorem taxes	23.7		27.0
Capital expenditure accruals	23.6		22.3
Onerous performance obligations	16.3		17.0
Other	48.6		57.6
Other current liabilities	$	146.1	$	174.8

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Organization and Summary of Significant Agreements (Details Textuals) - shares	6 Months Ended
	Jun. 30, 2016	Jan. 07, 2016
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100.00%
Partnership name	EnLink Midstream Partners GP, LLC
Managing Member Or General Partner Ownership Interest In The Limited Partnership	0.40%
ENLC
Business Acquisition [Line Items]
Limited Liability Company (LLC) Or Limited Partnership (LP) Members Or Limited Partners Ownership Interest, Shares	88,528,451
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	23.00%
Tall Oak [Member] | ENLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	16.00%	16.00%

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Significant Accounting Policies (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 22.2	$ 23.8

XML

Acquisition (Details Textuals) - USD ($) $ in Millions				6 Months Ended
	Jan. 07, 2016	Nov. 16, 2015	Oct. 01, 2015	Jun. 30, 2016	Jun. 30, 2016
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life					13 years 8 months
Matador [Member]
Business Acquisition [Line Items]
Consideration Transferred			$ 141.3
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Finite-Lived Intangible Asset, Useful Life			15 years
Deadwood Acquisition [Member]
Business Acquisition [Line Items]
Consideration Transferred		$ 40.1
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Business Combination, Consideration Transferred, Other		$ 1.5
Tall Oak [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs				$ 3.7	$ 3.7
Consideration Transferred	$ 1,442.2
BusinessCombinationFirstInstallment	1,020.0
Business Combination Total Installment Payable	500.0
Business Combination, Installment, Long-term Payable	$ 250.0				$ 250.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual				72.2
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual				$ 23.5
Finite-Lived Intangible Asset, Useful Life	15 years
Business Combination Cash Consideration Transferred	$ 806.4
Common Unit | Tall Oak [Member]
Business Acquisition [Line Items]
Common Unit, Issued	15,564,009
EnLink Midstream LP [Member] | Tall Oak [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	84.00%
ENLC | Tall Oak [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	16.00%			16.00%	16.00%
Business Combination Cash Consideration Transferred	$ 22.2
EnLink Midstream Partners, LP | Tall Oak [Member]
Business Acquisition [Line Items]
Business Combination Cash Consideration Transferred	$ 784.2

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Acquisition (Details) - USD ($) $ in Millions			6 Months Ended
	Jan. 07, 2016	Oct. 01, 2015	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Issuance of common units			$ 214.9
Assets acquired [Abstract]
Goodwill			1,541.3	$ 2,413.9	$ 3,731.2
Tall Oak [Member]
Business Acquisition [Line Items]
Issuance of common units	$ 214.9
Business Combination Cash Consideration Transferred	806.4
Business Combination, Consideration Transferred, Liabilities Incurred	420.9		420.9
Consideration Transferred	1,442.2
Assets acquired [Abstract]
Current assets	23.0
Property, plant and equipment	423.2
Intangibles	1,034.3
Liabilities assumed:
Current liabilities	(38.3)
Net assets acquired	$ 1,442.2
Matador [Member]
Business Acquisition [Line Items]
Consideration Transferred		$ 141.3
Assets acquired [Abstract]
Current assets		1.1
Property, plant and equipment		35.5
Intangibles		98.8
Goodwill		9.8
Liabilities assumed:
Current liabilities		(3.9)
Net assets acquired		$ 141.3
Common Stock [Member]
Business Acquisition [Line Items]
Issuance of common units			$ 214.9

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Acquisition (Proforma) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Pro forma total revenues	$ 1,283.3	$ 2,350.9
Pro forma net income	27.7	31.5
Pro forma net income attributable to EnLink Midstream, LLC	$ 12.2	$ 22.8
Basic	$ 0.07	$ 0.13
Diluted	$ 0.07	$ 0.13

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Acquisition (Phantom) (Details) - Tall Oak [Member] - USD ($) $ in Millions	Jan. 07, 2016	Jun. 30, 2016
Business Acquisition [Line Items]
Cash Acquired from Acquisition	$ 12.8
Debt Instrument, Unamortized Discount (Premium), Net	$ 79.1	$ 79.1

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Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Goodwill [Line Items]
Goodwill	$ 1,541.3	$ 3,731.2	$ 1,541.3	$ 3,731.2	$ 2,413.9
Impairment			(873.3)
Acquisition adjustment			$ 0.7
Finite-Lived Intangible Asset, Useful Life			13 years 8 months
Amortization of Intangible Assets	30.0	18.2	$ 57.5	29.7
Texas Operating Segment
Goodwill [Line Items]
Goodwill	231.1	1,185.0	231.1	1,185.0	703.5
Impairment			(473.1)
Acquisition adjustment			0.7
Louisiana Operating Segment
Goodwill [Line Items]
Goodwill	0.0	786.8	0.0	786.8	0.0
Impairment			0.0
Oklahoma Operating Segment
Goodwill [Line Items]
Goodwill	190.3	190.3	190.3	190.3	190.3
Impairment			0.0
Crude And Condensate Segment
Goodwill [Line Items]
Goodwill	0.0	142.1	0.0	142.1	93.2
Impairment			(93.2)
Corporate Segment
Goodwill [Line Items]
Goodwill	$ 1,119.9	$ 1,427.0	1,119.9	$ 1,427.0	$ 1,426.9
Impairment			$ (307.0)
Minimum
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life			10 years
Maximum
Goodwill [Line Items]
Finite-Lived Intangible Asset, Useful Life			20 years

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life			13 years 8 months
Finite-Lived Intangible Assets, Gross	$ 1,778.8		$ 1,778.8		$ 744.5
Finite-Lived Intangible Assets, Accumulated Amortization	(112.1)		(112.1)		(54.6)
Finite-Lived Intangible Assets, Net	1,666.7		1,666.7		$ 689.9
Finite-lived Intangible Assets Acquired			1,034.3
Amortization of Intangible Assets	$ 30.0	$ 18.2	$ 57.5	$ 29.7

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Goodwill and Intangible Assets (Amortization Expense Table) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2016 (remaining)	$ 58.4
2017	116.7
2018	116.7
2019	116.7
2020	116.7
Thereafter	1,141.5
Total	$ 1,666.7	$ 689.9

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Affiliate Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Due to Related Parties, Current	$ 10.4		$ 10.4	$ 10.4		$ 14.8
Devon Energy Corporation
Related Party Transaction [Line Items]
Concentration Risk, Percentage	18.60%	14.20%		19.70%	15.70%
Due from Affiliate, Current	$ 72.6		72.6	$ 72.6		110.8
Due to Related Parties, Current	$ 10.4		$ 10.4	$ 10.4		$ 14.8
Devon Energy Production Company
Related Party Transaction [Line Items]
Minimum Volume Commitment			5 years
Term Of Contract			13 years

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Long-Term Debt (Indebtedness Table) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net	$ (22.2)	$ (23.8)
Other Long-term Debt	0.0	0.2
Long-term Debt	3,364.1	3,066.0
Partnership [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	697.0	414.0
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	15.1	0.0
2.7% Senior Notes due 2019
Debt Instrument [Line Items]
Senior Notes	399.7	399.6
7.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes	180.0	181.4
4.4% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes	552.7	552.9
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Senior Notes	748.8	748.8
5.6% Senior Notes due 2044
Debt Instrument [Line Items]
Senior Notes	349.8	349.8
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Senior Notes	$ 443.2	$ 443.1

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	100.00%
Line of Credit Facility, Interest Rate During Period	0.50%
Percentage Rate	1.00%
ENLC
Debt Instrument [Line Items]
Limited Liability Company (LLC) Or Limited Partnership (LP) Members Or Limited Partners Ownership Interest, Shares	88,528,451
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	23.00%
Minimum
Debt Instrument [Line Items]
Interest Coverge Ratio	2.50
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 250.0
Line of Credit Facility, Interest Rate During Period	4.25%
Line of Credit Facility, Amount Outstanding	$ 15.1	$ 0.0
Line of Credit Facility, Remaining Borrowing Capacity	$ 234.9
ENLC Credit Facility [Member] | Maximum
Debt Instrument [Line Items]
Leverage ratios	4.00
ENLC Credit Facility [Member] | AcquisitionPeriod [Member] | Maximum
Debt Instrument [Line Items]
Leverage ratios	4.50
Partnership [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,500.0
Line Of Credit Facility, Additional Borrowing Limit	500.0
Letters of Credit Outstanding, Amount	11.1
Line of Credit Facility, Amount Outstanding	697.0	$ 414.0
Line of Credit Facility, Remaining Borrowing Capacity	$ 791.9
Partnership [Member] | Maximum
Debt Instrument [Line Items]
Leverage ratios	5.0
Conditional acquisition purchase price	$ 50.0
Partnership [Member] | Revolving Credit Facility [Member] | Maximum
Debt Instrument [Line Items]
Leverage ratios	5.5
Partnership [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	0.50%
Partnership [Member] | Eurodollar [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	1.00%
Letter of Credit [Member] | ENLC
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 125.0
Letter of Credit [Member] | EnLink Midstream Partners, LP
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500.0
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	2.20%	1.80%

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Long-term Debt (Phantom) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	0.50%
Accumulated Amortization, Deferred Finance Costs	$ 7.0	$ 5.1
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate During Period	2.20%	1.80%
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	$ 0.3	$ 0.4
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	$ (17.5)	$ (18.9)
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	$ (2.7)	$ (2.9)
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	$ 0.2	$ 0.2
5.05% Senior Notes due 2045
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.05%	5.05%
Debt Instrument, Unamortized Discount (Premium), Net	$ 6.8	$ 6.9
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%	4.15%
Debt Instrument, Unamortized Discount (Premium), Net	$ 1.2	$ 1.2

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Income Tax (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Loss Carryforwards [Line Items]
Tax expense (benefit) at statutory federal rate (35%)	$ 0.5	$ 8.4	$ (160.0)	$ 17.4
State income taxes expense (benefit), net of federal tax benefit	0.0	0.6	(14.9)	1.2
Income tax expense (benefit) from partnership	(2.3)	0.7	(1.3)	1.9
Non-deductible expense related to asset impairment	0.0	0.0	173.9	0.0
Other	0.0	0.5	0.7	0.4
Income Tax Expense (Benefit)	(1.8)	10.2	(1.6)	20.9
Enlink midstream, LLC
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$ (1.8)	$ 10.2	$ (1.6)	$ 20.9

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Certain Provision of the Partnership Agreement (Textual) (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended			6 Months Ended
	Jan. 07, 2016	Mar. 16, 2015	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Nov. 30, 2014
Subsidiary Sale Of Stock [Line Items]
Proceeds from Issuance of common units						$ 52.3	$ 4.1
Preferred Units, Issued	50,000,000
Percentage Of Avaliable Cash to Distribute			100.00%			100.00%
Distribution Made to Limited Partner, Distribution Period						45 days
Shares Issued, Price Per Share	$ 15.00
Proceeds from Issuance of Preferred Limited Partners Units	$ 724.1					$ 724.1	$ 0.0
Conversion VWAP Percentage						150.00%
Percent Of Issue Price						140.00%
Annual Rate On Issue Price Payable In-Kind						8.50%
Annual Rate On Issue Price Payable In Cash						7.50%
Annual Rate On Issue Price						1.00%
Net Income (Loss) Allocated To Preferred			$ 18.0			$ 29.8
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, 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						$ 52.3
Payments of Stock Issuance Costs						$ 0.5
Aggregate Amount Of Equity Securities Allowed Under Equity Distribution Agreement								$ 350.0
Stock Issued During Period, Value, New Issues			3,300,000			3,300,000
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement			$ 264.4			$ 264.4
Common Units
Subsidiary Sale Of Stock [Line Items]
Distributions Declared, Per Unit			$ 0.39	$ 0.39	$ 0.39
Distribution Made to Limited Partner, Distribution Date			Aug. 11, 2016	May 12, 2016	Feb. 11, 2016
Common Class C [Member]
Subsidiary Sale Of Stock [Line Items]
Stock Issued During Period, Shares, Acquisitions		6,704,285
Paid In Kind Dividends				233,107	209,044
Preferred Stock [Member]
Subsidiary Sale Of Stock [Line Items]
Preferred Stock Dividends, Shares			1,083,589	992,445

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Incentive Distribution Made to Managing Member or General Partner [Line Items]
General Partner interest in net income	$ 10.6	$ 19.1	$ 18.0	$ 45.6
General Partner Interest
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Income allocation for incentive distributions	14.2	11.3	28.0	20.1
Unit-based compensation attributable to ENLC’s restricted units	(3.6)	(3.9)	(7.6)	(10.9)
General Partner share of net income (loss)	0.0	0.2	(2.4)	0.3
General Partner interest in drop down transactions	$ 0.0	$ 11.5	$ 0.0	$ 36.1

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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, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Capital Unit [Line Items]
EnLink Midstream, LLC interest in net income (loss)	$ 0.8		$ 14.5		$ (456.8)	$ 30.8
Total distributed earnings	46.4		41.4		92.5	81.8
Total undistributed loss	$ (45.6)		$ (26.9)		$ (549.3)	$ (51.0)
Basic common unit (usd per unit)	$ 0.01		$ 0.09		$ (2.55)	$ 0.19
Diluted common unit (usd per unit)	0.01		0.09		$ (2.55)	$ 0.19
Distribution paid (usd per unit)	$ 0.255	$ 0.255	$ 0.25	$ 0.245
Common Unit
Capital Unit [Line Items]
EnLink Midstream, LLC interest in net income (loss)	$ 1.2		$ 14.4		$ (451.7)	$ 30.6
Total distributed earnings	45.9		41.1		91.5	81.3
Total undistributed loss	(44.7)		(26.7)		(543.2)	(50.7)
Restricted Stock Units (RSUs)
Capital Unit [Line Items]
EnLink Midstream, LLC interest in net income (loss)	(0.4)		0.1		(5.1)	0.2
Total distributed earnings	0.5		0.3		1.0	0.5
Total undistributed loss	$ (0.9)		$ (0.2)		$ (6.1)	$ (0.3)

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Capital Unit [Line Items]
Weighted Average Number of Shares Outstanding, Basic	180.0	164.2	179.4	164.2
Weighted Average Number Diluted Shares Outstanding Adjustment	0.8	0.4	0.0	0.4
Weighted average common shares outstanding: Basic (usd per share)	180.8	164.6	179.4	164.6
Common Unit
Capital Unit [Line Items]
Weighted Average Limited Partnership Units Outstanding, Basic	180.0	164.2	179.4	164.2

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Asset Retirement Obligation (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Current	$ 0.0		$ 1.1
Asset Retirement Obligation	13.2	$ 13.7	$ 14.0	$ 20.6
Revisions to existing liabilities	(0.4)	(4.0)
Accretion	0.2	0.3
Liabilities settled	$ (0.6)	$ (3.2)

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Investment in Unconsolidated Affiliate (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Contributions	$ 34.7		$ 41.8
Distributions	5.6	$ 12.4	14.8	$ 19.2
Equity in income of equity investments	0.8	5.9	(1.6)	9.7
Investment in equity investment	299.7		299.7		$ 274.3
Gulf Coast Fractionators [Member]
Schedule of Equity Method Investments [Line Items]
Contributions	0.0		0.0
Distributions	0.5	4.2	3.5	6.9
Equity in income of equity investments	0.5	$ 2.9	(1.2)	$ 6.3
Investment in equity investment	$ 47.9		$ 47.9		52.6
Ownership Percentage	38.75%	38.75%	38.75%	38.75%
Howard Energy Partners [Member]
Schedule of Equity Method Investments [Line Items]
Contributions	$ 34.7		$ 41.8
Distributions	5.1	$ 8.2	11.3	$ 12.3
Equity in income of equity investments	0.3	$ 3.0	(0.4)	$ 3.4
Investment in equity investment	$ 251.8		$ 251.8		$ 221.7
Ownership Percentage	31.00%	31.00%	31.00%	31.00%

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Investment in Unconsolidated Affiliate (Phantom) (Details)	Jun. 30, 2016	Jun. 30, 2015
Gulf Coast Fractionators [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Percentage	38.75%	38.75%
Howard Energy Partners [Member]
Schedule of Equity Method Investments [Line Items]
Ownership Percentage	31.00%	31.00%

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Employee Incentive Plans (Textuals) (Details) - USD ($) $ in Millions		6 Months Ended
	Apr. 07, 2016	Jun. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized	5,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	14,070,000
Restricted Stock Units (RSUs) | ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units		$ 18.6
Unrecognized compensation costs, weighted average period for recognition		1 year 8 months
EnLink Midstream Partners, LP | Performance Based Restricted Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period		3 years
EnLink Midstream Partners, LP | Performance Based Restricted Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units		$ 4.4
Unrecognized compensation costs, weighted average period for recognition		2 years
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		$ 19.0
Unrecognized compensation costs, weighted average period for recognition		1 year 9 months
Enlink midstream, LLC | Performance Based Restricted Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted incentive units		$ 4.2
Vesting Period		3 years
Unrecognized compensation costs, weighted average period for recognition		2 years
Minimum | EnLink Midstream Partners, LP | Performance Based Restricted Unit
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 | Enlink midstream, LLC | Performance Based Restricted Unit
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 | EnLink Midstream Partners, LP | Performance Based Restricted Unit
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 | Enlink midstream, LLC | Performance Based Restricted Unit
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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Employee Incentive Plans (Expense Schedule) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 7.4	$ 7.7	$ 15.4	$ 21.5
Amount of related income tax expense recognized in income	1.8	1.5	3.7	4.6
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	5.7	6.6	12.0	18.5
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	1.7	1.1	3.4	3.0
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	$ 2.7	$ 3.7	$ 5.6	$ 9.2

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Employee Incentive Plans (Compensation Schedule) (Details) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) $ / shares shares
ENLK Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	1,253,729
Granted (Units)	1,046,685
Vested (Units)	(297,439)
Forfeited (Units)	(40,998)
Non-vested, end of period (Units)	1,961,977
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 29.59
Granted (usd per share) | $ / shares	10.03
Vested (usd per share) | $ / shares	30.33
Forfeited (usd per share) | $ / shares	22.17
Non-vested, end of period (usd per share) | $ / shares	$ 19.20
Aggregate intrinsic value, end of period (in millions) | $	$ 32.6
Units withheld for payroll taxes on behalf of employees	85,366
ENLC Restricted Units | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (Units)	1,148,893
Granted (Units)	1,038,619
Vested (Units)	(320,497)
Forfeited (Units)	(37,952)
Non-vested, end of period (Units)	1,829,063
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 34.78
Granted (usd per share) | $ / shares	9.44
Vested (usd per share) | $ / shares	36.92
Forfeited (usd per share) | $ / shares	23.95
Non-vested, end of period (usd per share) | $ / shares	$ 20.24
Aggregate intrinsic value, end of period (in millions) | $	$ 29.1
Units withheld for payroll taxes on behalf of employees	91,256
Enlink midstream, LLC | Performance Based Restricted Unit
Number of Units
Non-vested, beginning of period (Units)	105,080
Granted (Units)	242,646
Forfeited (Units)	(2,525)
Non-vested, end of period (Units)	345,201
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 40.50
Granted (usd per share) | $ / shares	9.59
Forfeited (usd per share) | $ / shares	41.31
Non-vested, end of period (usd per share) | $ / shares	$ 18.76
Aggregate intrinsic value, end of period (in millions) | $	$ 5.5
EnLink Midstream Partners, LP | Performance Based Restricted Unit
Number of Units
Non-vested, beginning of period (Units)	118,126
Granted (Units)	258,078
Forfeited (Units)	(2,798)
Non-vested, end of period (Units)	373,406
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (usd per share) | $ / shares	$ 35.41
Granted (usd per share) | $ / shares	9.81
Forfeited (usd per share) | $ / shares	36.18
Non-vested, end of period (usd per share) | $ / shares	$ 17.71
Aggregate intrinsic value, end of period (in millions) | $	$ 6.2

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Employee Incentive Plans (Intrinsic and Fair Value of Units Vested) (Details) - Restricted Stock Units (RSUs) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
ENLK Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 0.1	$ 0.4	$ 3.8	$ 7.2
Fair value of units vested	0.0	0.5	9.0	7.5
ENLC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	0.0	0.6	3.8	8.9
Fair value of units vested	$ 0.0	$ 0.6	$ 11.8	$ 9.2

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Employee Incentive Plans Total Shareholder Return Unit Summary (Details) - Performance Based Restricted Unit - $ / shares	Feb. 19, 2016	Jan. 22, 2016
Enlink midstream, LLC
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Beginning TSR Price	$ 15.38	$ 15.38
Risk-free interest rate	0.89%	1.10%
Volatility factor	52.05%	46.02%
Distribution yield	14.00%	8.60%
EnLink Midstream Partners, LP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Beginning TSR Price	$ 14.82	$ 14.82
Risk-free interest rate	0.89%	1.10%
Volatility factor	42.33%	39.71%
Distribution yield	19.20%	12.10%

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Derivatives (Summary of Derivative Income Expense) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative activity	$ (5.7)	$ 1.2	$ (6.1)	$ 1.4
Commodity Swap
Derivative Instruments, Gain (Loss) [Line Items]
Change in fair value of derivatives	(8.4)	(2.5)	(14.4)	(6.3)
Realized gain on derivatives	$ 2.7	$ 3.7	$ 8.3	$ 7.7

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Derivatives (Schedule of Derivative Assets Liabilities) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Fair value of derivative assets — current	$ 5.3	$ 16.8
Fair value of derivative liabilities — current	(5.8)	(2.9)
Fair value of derivative liabilities — long term	0.0	(0.1)
Net fair value of derivatives	$ (0.5)	$ 13.8

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Derivatives (Derivatives Outstanding) (Details) gal in Millions, bbl in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2016 USD ($) bbl MMBTU gal	Dec. 31, 2015 USD ($)
Derivative [Line Items]
Net fair value of derivatives	$ (0.5)	$ 13.8
Condensate [Member] | Swap [Member] | Short [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	(0.1)
Net fair value of derivatives	$ (0.5)
Gas [Member] | Swap [Member] | Short [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	(6.3)
Net fair value of derivatives	$ (2.9)
Gas [Member] | Swap [Member] | Long [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	(1.3)
Net fair value of derivatives	$ (0.1)
Liquids [Member] | Swap [Member] | Short [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	(31.9)
Net fair value of derivatives	$ 3.4
Liquids [Member] | Swap [Member] | Long [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | gal	(11.4)
Net fair value of derivatives	$ (0.4)

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Derivatives (Details Textuals) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	$ (0.5)		$ (0.5)
Maximum counterparty loss	5.3		5.3
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0.0	$ 3.6	$ 0.0	$ 3.6

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Fair Value Measurement (Fair Measurement on a Recurring Nonrecurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
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	$ (0.5)	$ 13.8

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Fair Value Measurement (Fair Value of Financial Instrument) (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 3,364.1	$ 3,066.0
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	3,364.1	3,066.0
Total Installment Payable	446.5	0.0
Obligations under capital lease	12.3	16.7
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	3,148.5	2,585.5
Total Installment Payable	451.6	0.0
Obligations under capital lease	$ 11.5	$ 15.6

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Fair Value Measurement (Details Textuals) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unsecured Debt	$ 2,674.8	$ 2,674.8
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	$ 697.0	$ 414.0
ENLC Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 15.1	$ 0.0

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Fair Value Measurement (Phantom) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unsecured Debt	$ 2,674.8	$ 2,674.8
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%

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

XML

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Product sales	$ 738.3	$ 956.2	$ 1,326.8	$ 1,626.9
Product sales - affiliates	31.7	31.7	56.2	47.9
Midstream services	108.3	135.9	222.8	238.3
Midstream services - affiliates	160.6	149.5	323.2	300.5
Cost of sales	(732.4)	(968.2)	(1,318.6)	(1,625.6)
Operating expenses	(100.1)	(109.1)	(198.3)	(207.6)
Loss on derivative activity	(5.7)	1.2	(6.1)	1.4
Segment profit	200.7	197.2	406.0	381.8
Depreciation and amortization	(124.9)	(97.7)	(246.8)	(189.0)
Impairments	0.0	0.0	(873.3)	0.0
Goodwill	1,541.3	3,731.2	1,541.3	3,731.2	$ 2,413.9
Capital expenditures	140.2	164.8	260.6	340.5
Segment identifiable assets	10,162.3		10,162.3		9,541.3
Texas Operating Segment
Segment Reporting Information [Line Items]
Product sales	41.9	81.2	104.4	131.0
Product sales - affiliates	72.7	35.0	110.0	60.9
Midstream services	23.2	36.0	50.6	55.6
Midstream services - affiliates	111.9	115.8	222.2	231.3
Cost of sales	(103.6)	(118.4)	(194.9)	(185.6)
Operating expenses	(43.0)	(45.5)	(82.3)	(92.6)
Loss on derivative activity	0.0	0.0	0.0	0.0
Segment profit	103.1	104.1	210.0	200.6
Depreciation and amortization	(48.7)	(42.8)	(94.9)	(79.2)
Impairments			(473.1)
Goodwill	231.1	1,185.0	231.1	1,185.0	703.5
Capital expenditures	57.2	80.9	80.5	154.4
Segment identifiable assets	3,179.9		3,179.9		3,709.5
Louisiana Operating Segment
Segment Reporting Information [Line Items]
Product sales	399.5	401.2	687.2	773.4
Product sales - affiliates	15.2	17.0	22.6	24.1
Midstream services	52.7	63.2	107.9	121.1
Midstream services - affiliates	25.5	0.3	38.2	0.4
Cost of sales	(425.5)	(418.2)	(727.6)	(789.1)
Operating expenses	(25.4)	(27.2)	(48.7)	(51.5)
Loss on derivative activity	0.0	0.0	0.0	0.0
Segment profit	42.0	36.3	79.6	78.4
Depreciation and amortization	(28.6)	(26.9)	(57.9)	(54.4)
Impairments			0.0
Goodwill	0.0	786.8	0.0	786.8	0.0
Capital expenditures	14.1	14.7	36.8	29.9
Segment identifiable assets	2,330.9		2,330.9		2,309.3
Oklahoma Operating Segment
Segment Reporting Information [Line Items]
Product sales	8.9	0.1	16.7	0.1
Product sales - affiliates	22.5	1.7	33.1	5.4
Midstream services	18.0	9.8	33.1	20.5
Midstream services - affiliates	41.7	29.1	86.7	60.3
Cost of sales	(31.6)	(2.0)	(50.9)	(7.1)
Operating expenses	(11.8)	(9.1)	(24.6)	(16.1)
Loss on derivative activity	0.0	0.0	0.0	0.0
Segment profit	47.7	29.6	94.1	63.1
Depreciation and amortization	(34.8)	(11.8)	(68.6)	(25.3)
Impairments			0.0
Goodwill	190.3	190.3	190.3	190.3	190.3
Capital expenditures	63.1	12.3	132.3	17.5
Segment identifiable assets	2,413.6		2,413.6		873.4
Crude And Condensate Segment
Segment Reporting Information [Line Items]
Product sales	288.0	473.7	518.5	722.4
Product sales - affiliates	0.9	14.0	1.1	14.0
Midstream services	14.4	26.9	31.2	41.1
Midstream services - affiliates	4.0	4.3	9.2	8.5
Cost of sales	(273.8)	(465.6)	(488.9)	(700.3)
Operating expenses	(19.9)	(27.3)	(42.7)	(47.4)
Loss on derivative activity	0.0	0.0	0.0	0.0
Segment profit	13.6	26.0	28.4	38.3
Depreciation and amortization	(10.6)	(14.5)	(21.0)	(26.9)
Impairments			(93.2)
Goodwill	0.0	142.1	0.0	142.1	93.2
Capital expenditures	0.9	54.4	4.2	132.0
Segment identifiable assets	780.6		780.6		898.0
Corporate Segment
Segment Reporting Information [Line Items]
Product sales	0.0	0.0	0.0	0.0
Product sales - affiliates	(79.6)	(36.0)	(110.6)	(56.5)
Midstream services	0.0	0.0	0.0	0.0
Midstream services - affiliates	(22.5)	0.0	(33.1)	0.0
Cost of sales	102.1	36.0	143.7	56.5
Operating expenses	0.0	0.0	0.0	0.0
Loss on derivative activity	(5.7)	1.2	(6.1)	1.4
Segment profit	(5.7)	1.2	(6.1)	1.4
Depreciation and amortization	(2.2)	(1.7)	(4.4)	(3.2)
Impairments			(307.0)
Goodwill	1,119.9	1,427.0	1,119.9	1,427.0	1,426.9
Capital expenditures	4.9	$ 2.5	6.8	$ 6.7
Segment identifiable assets	$ 1,457.3		$ 1,457.3		$ 1,751.1

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting [Abstract]
Segment profits	$ 200.7	$ 197.2	$ 406.0	$ 381.8
General and administrative expenses	(30.3)	(28.1)	(65.4)	(70.8)
Loss on disposition of assets	(0.3)	0.0	(0.1)	0.0
Depreciation and amortization	(124.9)	(97.7)	(246.8)	(189.0)
Impairments	0.0	0.0	(873.3)	0.0
Operating income (loss)	$ 45.2	$ 71.4	$ (779.6)	$ 122.0

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		6 Months Ended
	Jan. 07, 2016	Jun. 30, 2016	Jun. 30, 2015
Other Significant Noncash Transactions [Line Items]
Business Combination, Installment, Current		$ 250.0
Other Significant Noncash Transaction, Value of Consideration Given		214.9	$ 180.0
Common Class C [Member]
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given			$ 180.0
Tall Oak [Member]
Other Significant Noncash Transactions [Line Items]
Business Combination, Consideration Transferred, Liabilities Incurred	$ 420.9	$ 420.9

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Supplemental Cash Flow Information (Phantom) (Details) - Tall Oak [Member] - USD ($) $ in Millions		6 Months Ended
	Jan. 07, 2016	Jun. 30, 2016
Other Significant Noncash Transactions [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ 79.1	$ 79.1
Business Combination, Installment, Long-term Payable	$ 250.0	$ 250.0

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Other Information (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Accrued interest	$ 23.6	$ 23.2
Accrued wages and benefits, including taxes	10.3	27.7
Accrued ad valorem taxes	23.7	27.0
Capital expenditure accruals	23.6	22.3
Onerous performance obligations	16.3	17.0
Other	48.6	57.6
Other current liabilities	$ 146.1	$ 174.8

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Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ in Millions	Aug. 01, 2016	Jul. 14, 2016
4.850% Senior Notes due 2026 [Member]
Subsequent Event [Line Items]
Debt Instrument, Face Amount		$ 500.0
Debt Instrument, Interest Rate, Stated Percentage		4.85%
Selling Price Of Debt Instrument		99.859%
Proceeds from Issuance of Debt		$ 495.7
EnLink Midstream LP [Member] | Delaware Basin JV [Member]
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	50.10%
Contribution of Property	$ 230.0
Future Capital Commitments	$ 285.0
NGP Natural Resources XI, L.P. [Member] | Delaware Basin JV [Member]
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	49.90%
Future Capital Commitments	$ 400.0
Payments to Acquire Interest in Joint Venture	$ 115.0