EnLink Midstream (ENLC) 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 24, 2016
Entity Information [Abstract]
Document Type	10-Q
Document Fiscal Period Focus	Q3
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Amendment Flag	false
Entity Registrant Name	Enlink Midstream, LLC
Entity Central Index Key	1,592,000
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		180,048,704

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 60.1	$ 18
Accounts receivable:
Trade, net of allowance for bad debt of $0.8 and $0.3, respectively	47.8	37.5
Accrued revenue and other	311.8	268.8
Related party	76.7	110.8
Fair value of derivative assets	4.3	16.8
Natural gas and NGLs inventory, prepaid expenses and other	39.5	41.8
Total current assets	540.2	493.7
Property and equipment, net of accumulated depreciation of $2,036.5 and $1,757.6, respectively	6,195.1	5,666.8
Intangible assets, net of accumulated amortization of $142.0 and $54.6, respectively	1,650.9	689.9
Goodwill	1,542.2	2,413.9
Investments in unconsolidated	266.4	274.3
Other assets, net	2.4	2.7
Total assets	10,197.2	9,541.3
Current liabilities:
Accounts payable and drafts payable	44.1	33.2
Accounts payable to related party	11.2	14.8
Accrued gas, NGLs, condensate and crude oil purchases	262.2	206.7
Fair value of derivative liabilities	6.5	2.9
Installment payable, net of discount of $7.4	242.6
Other current liabilities	196.3	174.8
Total current liabilities	762.9	432.4
Long-term debt	3,245.2	3,066
Fair value of derivative liabilities		0.1
Asset retirement obligation	13.4	12.9
Other long-term liabilities	49.8	65.9
Installment payable, net of discount of $32.8	217.2
Deferred tax liability	542.8	532.1
Redeemable non-controlling interest	6.2	7
Members' equity:
Members' equity (180,048,704 and 164,242,160 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)	1,926	2,285.7
Non-controlling interest	3,433.7	3,139.2
Total members' equity	5,359.7	5,424.9
Commitment and Contingencies (Note 15)
Total liabilities and members equity	$ 10,197.2	$ 9,541.3

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Assets:
Allowance for bad debt	$ 0.8	$ 0.3
Property and equipment accumulated depreciation	2,036.5	1,757.6
Intangible assets accumulated amortization	142	$ 54.6
Liabilities:
Current installment payable discount	7.4
Noncurrent installment payable discount	$ 32.8
Members' equity:
Common units issued	180,048,704	164,242,160
Common units outstanding	180,048,704	164,242,160

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Product sales	$ 771	$ 863.5	$ 2,097.8	$ 2,488.8
Product sales - affiliates	43.1	40.3	99.3	89.6
Midstream services	125.7	111.3	348.5	351.3
Midstream services - affiliates	165.3	150.3	488.5	449.3
Gain (loss) on derivative activity	(0.5)	5.2	(6.6)	6.6
Total revenues	1,104.6	1,170.6	3,027.5	3,385.6
Operating costs and expenses:
Cost of sales (1)	788.2	861.8	2,106.8	2,487.4
Operating expenses (2)	98	105	296.3	312.6
General and administrative (3)	29.3	34.8	94.7	105.6
Loss on disposition of assets	(3)	3.2	(2.9)	3.2
Depreciation and amortization	126.2	98.4	373	289.1
Impairments		799.2	873.3	799.2
Total operating costs and expenses	1,038.7	1,902.4	3,741.2	3,997.1
Operating income (loss)	65.9	(731.8)	(713.7)	(611.5)
Other income (expense):
Interest expense, net of interest income	(48.4)	(30.4)	(138.9)	(72.1)
Income (loss) from unconsolidated affiliates	1.1	6.4	(0.5)	16.1
Other income	0.1	0.1	0.1	0.6
Total other expense	(47.2)	(23.9)	(139.3)	(55.4)
Income (loss) before non-controlling interest and income taxes	18.7	(755.7)	(853)	(666.9)
Income tax benefit (provision)	(7.6)	(0.2)	(6)	(21.1)
Net income (loss)	11.1	(755.9)	(859)	(688)
Net income (loss) attributable to the non-controlling interest	10.4	(562.5)	(402.9)	(526.1)
Net income (loss) attributable to EnLink Midstream, LLC	0.7	(193.4)	(456.1)	(161.9)
Devon investment interest in net income				0.7
Enlink Midstream, LLC interest in net income (loss)	$ 0.7	$ (193.4)	$ (456.1)	$ (162.6)
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit		$ (1.18)	$ (2.54)	$ (0.99)
Diluted common unit		$ (1.18)	$ (2.54)	$ (0.99)

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Cost of sales	$ 788.2	$ 861.8	$ 2,106.8	$ 2,487.4
Operating expenses	98	105	296.3	312.6
General and administrative	29.3	34.8	94.7	105.6
Affiliated Entity
Cost of sales	33.7	51.9	126	91.7
Operating expenses	$ 0.1	0.1	$ 0.4	0.3
General and administrative		$ 0.1		$ 0.3

Consolidated Statements of Chan

Consolidated Statements of Changes in Members Equity - 9 months ended Sep. 30, 2016 - USD ($) $ in Millions	Common Units	Non-Controlling Interest	Total
Member equity, beginning balance at Dec. 31, 2015	$ 2,285.7	$ 3,139.2	$ 5,424.9
Units outstanding, beginning balance (in units) at Dec. 31, 2015	164,200,000		164,242,160
Increase (Decrease) in Members' Equity
Unit-based compensation	$ 11.2	11.3	$ 22.5
Issuance of common units by the Partnership		110.6	110.6
Issuance of Preferred Units by the Partnership		724.1	724.1
Issuance of common units	$ 214.9		214.9
Issuance of common units (in units)	15,600,000
Conversion of restricted units for common, net of units withheld for taxes	$ (1.2)		(1.2)
Conversion of restricted units for common, net of units withheld for taxes (in units)	200,000
Non-controlling partner's impact of conversion of restricted units		(1.2)	(1.2)
Change in equity due to issuance of units by the Partnership	$ 10.5	(16.8)	(6.3)
Non-controlling interest distributions		(283.5)	(283.5)
Non-controlling interest contribution		151.5	151.5
Distribution to members	(139)		(139)
Contribution from Devon to the Partnership		1.4	1.4
Net loss	(456.1)	(402.9)	(859)
Member equity, end balance at Sep. 30, 2016	$ 1,926	$ 3,433.7	$ 5,359.7
Units outstanding, end balance (in units) at Sep. 30, 2016	180,000,000		180,048,704

Consolidated Statement of Chang

Consolidated Statement of Changes in Members Equity - Temporary Equity - 9 months ended Sep. 30, 2016 - USD ($) $ in Millions	Redeemable Non-controlling Interest	Total
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2015	$ 7
Increase (Decrease) in Temporary Equity
Distribution to redeemable non-controlling interest	(0.8)	$ (283.5)
Redeemable noncontrolling interest, end balance at Sep. 30, 2016	$ 6.2

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net loss	$ (859)	$ (688)
Adjustments to reconcile net income (loss) to net cash provided by operating activities, net of assets acquired or liabilities assumed:
Impairments	873.3	799.2
Depreciation and amortization	373	289.1
Accretion expense	0.4	0.4
(Gain) loss on disposition of assets	(2.9)	3.2
Deferred tax (benefit) expense	4.4	18.2
Non-cash unit-based compensation	22.5	28.9
(Gain) loss on derivatives recognized in net income (loss)	6.6	(6.6)
Cash settlements on derivatives	9.5	13
Amortization of debt issue costs	2.9	2.4
Amortization of net (premium) discounts on notes	36.9	(2.2)
Redeemable non-controlling interest expense	0.3	(2)
Distribution of earnings from unconsolidated affiliates	0.7	17.1
(Income) loss from unconsolidated affiliates	0.5	(16.1)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other	(17.9)	124.1
Natural gas and NGLs inventory, prepaid expenses and other	11.9	(28.6)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	49.4	(60.5)
Net cash provided by operating activities	512.5	491.6
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(423.7)	(450.3)
Acquisition of business, net of cash acquired	(791.5)	(330.6)
Proceeds from insurance settlement	0.3
Proceeds from sale of property	4.7	0.4
Investment in unconsolidated affiliates	(45)	(8.1)
Distribution from unconsolidated affiliates in excess of earnings	51.6	14.3
Net cash used in investing activities	(1,203.6)	(774.3)
Cash flows from financing activities:
Proceeds from borrowings	1,667.7	2,604.4
Payments on borrowings	(1,484.5)	(1,773.2)
Payments on capital lease obligations	(3.2)	(2.5)
Decrease in drafts payable		(12.6)
Debt financing costs	(4.7)	(9.5)
Mandatorily redeemable non-controlling interest	(4)
Conversion of restricted units, net of units withheld for taxes	(1.2)	(2.8)
Conversion of Partnership's restricted units, net of units withheld for taxes	(1.2)	(2.5)
Proceeds from issuance of Partnership's common units	110.6	12.9
Distributions to non-controlling partners	(284.3)	(266.8)
Distribution to members	(139)	(120.6)
Contributions from Devon	1.4	28.8
Distributions to Devon for net assets acquired		(171)
Proceeds from Issuance of Preferred Limited Partners Units	724.1
Contributions by non-controlling interest	151.5	12.2
Net cash provided by financing activities	733.2	296.8
Net increase in cash and cash equivalents	42.1	14.1
Cash and cash equivalents, beginning of period	18	68.4
Cash and cash equivalents, end of period	60.1	82.5
Cash paid for interest	71.2	46
Cash paid (refund) for income taxes	$ (5.6)	$ 13.7

General

General	9 Months Ended
	Sep. 30, 2016
General
General	ENLINK MIDSTREAM, LLC Notes to Condensed Consolidated Financial Statements September 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 (“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) 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 September 30, 2016, our interests in the Partnership and EnLink Oklahoma T.O. consist of the following:  88,528,451 common units representing an aggregate 22.5% 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) 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, 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 crude oil from a producer site to an end user. The Partnership’s processing plants remove NGLs and CO 2 from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline. (c) 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.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Significant Accounting Policies
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) 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 August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-15, Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 addresses the classification and presentation of certain cash receipts and cash payments related to debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, and other specific cash flow issues. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and should be applied using a retrospective transition method to each period presented. Early application is permitted, including adoption in an interim period. In September 2016, we elected to early adopt ASU 2016-15 effective January 1, 2016. The adoption had no impact on our condensed consolidated financial statements or related disclosures. (c) Accounting Standards to be Adopted in Future Periods 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 or 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. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”) , which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncements will have on our condensed consolidated financial statements and related disclosures.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2016
Acquisitions
Acquisitions	(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. Purchase Price Allocation (in millions): Assets acquired: Current assets $ Property, plant and equipment Intangibles Goodwill Liabilities assumed: Current liabilities Total identifiable net assets $ 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 $783.6 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 $ Issuance of common units The Partnership’s total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018 Total consideration $ Purchase Price Allocation (in millions): Assets acquired: Current assets (including $12.8 million in cash) $ Property, plant and equipment Intangibles Liabilities assumed: Current liabilities Total identifiable net assets $ 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 nine months ended September 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 September 30, 2016, we recognized $149.5 million of revenues and $27.9 million of net loss related to the assets acquired. Pro Forma Information The following unaudited pro forma condensed financial information for the three and nine months ended September 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. Three Months Ended Nine Months Ended September 30, September 30, 2015 2015 Pro forma total revenues $ $ Pro forma net loss $ $ Pro forma net loss attributable to EnLink Midstream, LLC $ $ Pro forma net loss per common unit: Basic $ $ Diluted $ $

Goodwill and Intangible Assets

Goodwill and Intangible Assets	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets
Goodwill and Intangible Assets	(4) Goodwill and Intangible Assets Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. 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 due primarily 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 nine months ended September 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): Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (in millions) Nine Months Ended September 30, 2016 Balance, beginning of period $ $ — $ $ $ $ Impairment — — Acquisition adjustment — — — — Balance, end of period $ $ — $ $ — $ $ 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 Net Carrying Accumulated Carrying Amount Amortization Amount Nine Months Ended September 30, 2016 Customer relationships, beginning of period $ $ $ Acquisitions — Amortization expense — Customer relationships, end of period $ $ $ The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $29.9 million and $14.6 million for the three months ended September 30, 2016 and 2015, respectively, and $87.4 million and $44.3 million for the nine months ended September 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) $ 2017 2018 2019 2020 Thereafter Total $

Affiliate Transactions

Affiliate Transactions	9 Months Ended
	Sep. 30, 2016
Affiliate Transactions
Affiliate Transactions	(5) Affiliate Transactions The Partnership engages in various transactions with Devon and other affiliated entities. For the three and nine months ended September 30, 2016 and 2015, Devon was a significant customer to the Partnership. Devon accounted for 18.9% and 19.4% of the Partnership’s revenues for the three and nine months ended September 30, 2016, respectively, and 16.3% and 15.9% for the three and nine months ended September 30, 2015, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $76.7 million as of September 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 $11.2 million as of September 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.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Long-Term Debt.
Long-Term Debt	(6) Long-Term Debt As of September 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions): September 30, 2016 December 31, 2015 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Partnership credit facility, due 2020 (1) $ $ — $ $ $ — $ Company credit facility, due 2019 (2) — — — — 2.70% Senior unsecured notes due 2019 7.125% Senior unsecured notes due 2022 4.40% Senior unsecured notes due 2024 4.15% Senior unsecured notes due 2025 4.85% Senior unsecured notes due 2026 — — — 5.60% Senior unsecured notes due 2044 5.05% Senior unsecured notes due 2045 Other debt — — — — Debt classified as long-term $ $ $ $ $ $ Debt issuance cost (3) Long-term debt, net of unamortized issuance cost $ $ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.2% at September 30, 2016 and 1.8% at December 31, 2015. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.0% at September 30, 2016. (3) Net of amortization of $8.0 million at September 30, 2016 and $5.1 million at December 31, 2015. 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 September 30, 2016 there was $23.1 million in outstanding borrowings under the credit facility, leaving approximately $226.9 million available for future borrowing based on the borrowing capacity of $250.0 million. The Company expects 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, and 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 September 30, 2016, there were $11.0 million in outstanding letters of credit and $75.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.4 billion 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. Senior Unsecured Notes due 2026 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 were used to repay outstanding borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Taxes
Income Taxes	(7) Income Taxes Income taxes included in the condensed consolidated financial statements were as follows for the periods presented: Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) (in millions) ENLC income tax expense $ $ $ $ Total income tax expense $ $ $ $ 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) (in millions) Tax expense (benefit) at statutory federal rate (35%) $ $ $ $ State income taxes expense (benefit), net of federal tax benefit Income tax expense from partnership Non-deductible expense related to asset impairment Other — Total income tax expense $ $ $ $

Certain Provision of the Partne

Certain Provision of the Partnership Agreement	9 Months Ended
	Sep. 30, 2016
Certain Provision of the Partnership Agreement
Certain Provisions of the Partnership Agreement	(8) Certain Provisions of the Partnership Agreement (a) 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 nine months ended September 30, 2016, the Partnership sold an aggregate of 6.7 million common units under the BMO EDA, generating proceeds of approximately $110.6 million (net of approximately $1.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of September 30, 2016, approximately $205.3 million remains available to be issued under the BMO EDA. (b) 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) 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. Distributions on the Preferred Units for the three months ended March 31, 2016 and June 30, 2016, were paid-in kind through the issuance of 992,445 and 1,083,589 Preferred Units on May 12, 2016 and August 11, 2016, respectively. A distribution on the Preferred Units was declared for the three months ended September 30, 2016 which will result in the issuance of 1,106,616 additional Preferred Units on November 11, 2016. (d) 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 nine months ended September 30, 2016 is provided below: Declaration period Distribution/unit Date paid/payable 2016 Fourth Quarter of 2015 $ February 11, 2016 First Quarter of 2016 $ May 12, 2016 Second Quarter of 2016 $ August 11, 2016 Third Quarter of 2016 $ November 11, 2016 (e) 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 nine months ended September 30, 2016 and 2015 (in millions): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Income allocation for incentive distributions $ $ $ $ Unit-based compensation attributable to ENLC’s restricted units General Partner share of net income (loss) — General Partner interest in drop down transactions — — — General Partner interest in net income $ $ $ $

Earnings per Unit and Dilution

Earnings per Unit and Dilution Computations	9 Months Ended
	Sep. 30, 2016
Earnings per Unit and Dilution Computations
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 nine months ended September 30, 2016 and 2015 (in millions, except per unit amounts): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 EnLink Midstream, LLC interest in net income (loss) $ $ $ $ Distributed earnings allocated to: Common units (1) (2) $ $ $ $ Unvested restricted units (1) (2) Total distributed earnings $ $ $ $ Undistributed loss allocated to: Common units $ $ $ $ Unvested restricted units Total undistributed loss $ $ $ $ Net income (loss) allocated to: Common units $ $ $ $ Unvested restricted units Total net income (loss) $ $ $ $ Basic and diluted net income (loss) per unit: Basic $ — $ $ $ Diluted $ — $ $ $ (1) Three months ended September 30, 2016 and 2015 represents a declared distribution of $0.255 per unit payable November 14, 2016 and a distribution of $0.255 per unit paid on November 13, 2015, respectively. (2) Represents a declared distribution of $0.255 per unit payable on November 14, 2016, and distributions paid of $0.255 on August 12, 2016, May 12, 2016 and November 13, 2015, $0.25 per unit on August 14, 2015 and $0.245 per unit on May 15, 2015 for the nine months ended September 30, 2016 and 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Basic and diluted earnings per unit: Weighted average common units outstanding Diluted weighted average units outstanding: Weighted average basic common units outstanding Dilutive effect of restricted incentive units issued — — — Total weighted average diluted common units outstanding 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.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligations
Asset Retirement Obligations	(10) Asset Retirement Obligations The schedule below summarizes the changes in the Partnership’s liabilities for asset retirement obligations: Nine Months Ended September 30, 2016 2015 (in millions) Beginning asset retirement obligations $ $ Revisions to the fair values of existing liabilities Accretion expense Liabilities settled Ending asset retirement obligations $ $ Asset retirement obligations of $13.4 million and $12.9 million were included in “Asset retirement obligations” as noncurrent liabilities on the Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015, respectively. Asset retirement obligations of $1.1 million were included in “Other current liabilities” on the Condensed Consolidated Balance Sheets as of December 31, 2015. There were no asset retirement obligations included in “Other current liabilities” on the Condensed Consolidated Balance Sheet as of September 30, 2016.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2016
Investment in Unconsolidated Affiliates
Investment in Unconsolidated Affiliates	(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 September 30, 2016 and 2015 and approximately 31.0% common unit ownership interest in Howard Energy Partners (“HEP”) at September 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 Howard Energy Fractionators Partners Total Three Months Ended September 30, 2016 Contributions (1) $ — $ $ Distributions (2) $ $ $ Equity in income $ $ $ September 30, 2015 Contributions $ — $ $ Distributions $ $ $ Equity in income $ $ $ Nine Months Ended September 30, 2016 Contributions (1) $ — $ $ Distributions (2) $ $ $ Equity in income $ $ $ September 30, 2015 Contributions $ — $ $ Distributions $ $ $ Equity in income $ $ $ (1) Contributions for the three and nine months ended September 30, 2016 include $3.2 and $32.7 million, respectively, of contributions to HEP for preferred units, which were redeemed during the third quarter 2016. (2) Distributions for the three and nine months ended September 30, 2016 include a redemption of $32.7 million of preferred units. The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): September 30, December 31, 2016 2015 Gulf Coast Fractionators $ $ Howard Energy Partners Total investment in unconsolidated affiliates $ $

Employee Incentive Plans

Employee Incentive Plans	9 Months Ended
	Sep. 30, 2016
Employee Incentive Plans
Employee Incentive Plans	(12) Employee Incentive Plans (a) 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Cost of unit-based compensation charged to general and administrative expense $ $ $ $ Cost of unit-based compensation charged to operating expense Total amount charged to income $ $ $ $ Interest of non-controlling partners in unit-based compensation $ $ $ $ Amount of related income tax expense recognized in income $ $ $ $ (b) 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 nine months ended September 30, 2016 is provided below: Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream Partners, LP Restricted Incentive Units: Units Fair Value Non-vested, beginning of period $ Granted Vested* Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ * 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 nine months ended September 30, 2016 and 2015, respectively, is provided below (in millions): Three Months Ended Nine Months Ended September 30, September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2016 2015 2016 2015 Aggregate intrinsic value of units vested $ $ $ $ Fair value of units vested $ $ $ $ As of September 30, 2016, there was $15.8 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 1.6 years. (c) 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 $ $ Risk-free interest rate % % Volatility factor % % Distribution yield % % The following table presents a summary of the Partnership’s performance units: Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream Partners, LP Performance Units: Units Fair Value Non-vested, beginning of period $ Granted Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ As of September 30, 2016 there was $3.8 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 1.8 years. (d) 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 nine months ended September 30, 2016 is provided below: Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream, LLC Restricted Incentive Units: Units Fair Value Non-vested, beginning of period $ Granted Vested* Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ * 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 nine months ended September 30, 2016 and 2015, respectively, are provided below (in millions): Three Months Ended Nine Months Ended September 30, September 30, EnLink Midstream LLC Restricted Incentive Units: 2016 2015 2016 2015 Aggregate intrinsic value of units vested $ $ $ $ Fair value of units vested $ $ $ $ As of September 30, 2016, there was $15.4 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 1.6 years. (e) 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 $ $ Risk-free interest rate % % Volatility factor % % Distribution yield % % The following table presents a summary of the Company’s performance units: Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream, LLC Performance Units: Units Fair Value Non-vested, beginning of period $ Granted Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ As of September 30, 2016, there was $3.7 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years.

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2016
Derivatives
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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Change in fair value of derivatives $ $ $ $ Realized gain on derivatives Gain (loss) on derivative activity $ $ $ $ The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions): September 30, December 31, 2016 2015 Fair value of derivative assets — current $ $ Fair value of derivative liabilities — current Fair value of derivative liabilities — long term — Net fair value of derivatives $ $ 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 $2.2 million as of September 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 September 30, 2016. The remaining term of the contracts extend no later than September 2017. September 30, 2016 Commodity Instruments Unit Volume Fair Value (In millions) NGL (short contracts) Swaps Gallons $ NGL (long contracts) Swaps Gallons Natural Gas (short contracts) Swaps MMBtu Natural Gas (long contracts) Swaps MMBtu Condensate (short contracts) Swaps MMbbls Total fair value of derivatives $ 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 September 30, 2016 of $4.3 million would be reduced to $1.6 million 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. Additionally, the Partnership entered into interest rate swaps during July 2016 in connection with the issuance of the 2026 Notes in July 2016. The Partnership has no open interest rate swap positions as of September 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Settlement gains on derivatives $ $ — $ $

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
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 assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions): September 30, 2016 December 31, 2015 Level 2 Level 2 Commodity Swaps* $ $ Total $ $ * 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): September 30, 2016 December 31, 2015 Carrying Fair Carrying Fair Value Value Value Value Long-term debt $ $ $ $ Installment Payables $ $ $ — $ — Obligations under capital lease $ $ $ $ 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 $75.0 million and $414.0 million in outstanding borrowings under its revolving credit facility as of September 30, 2016 and December 31, 2015, respectively. We had $23.1 million in outstanding borrowings under our credit facility as of September 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 September 30, 2016 and December 31, 2015, the Partnership had total borrowings under senior unsecured notes of $3.1 billion and $2.7 billion, respectively, 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 September 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.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies
Commitments and Contingencies	(15) Commitments and Contingencies (a) 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) 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. In the third quarter of 2016, in connection with the transition to the Partnership’s operational control of E2 Appalachian Compression, LLC in and preparation to commence operational control of E2 Ohio Compression, LLC, the Partnership discovered instances of noncompliance with air regulations and permits. This noncompliance was self-reported to the Ohio Environmental Protection Agency (“OEPA”), resulting in the issuance of notices of violations (“NOVs”). The Partnership and E2 Ohio are taking appropriate measures to achieve compliance with applicable requirements and cooperating with the OEPA to resolve the NOVs, and, while we do not have information concerning any fine or penalty that may be assessed, we do not believe any such fine or penalty will be material to the Partnerships’ operations. On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of the Partnership’s Louisiana operations, the Partnership made an offer of $0.1 million in the form of a Global Settlement to the Louisiana Department of Environmental Quality (“LDEQ”) to resolve environmental noncompliance discovered or investigated during the Partnership’s assessment, which involved several of the Partnership’s Louisiana facilities. The noncompliance proposed to be covered by the Global Settlement include noncompliance that was self-reported to the LDEQ as the result of the Partnership’s assessment as well as noncompliance that was the subject of notices of potential violations and NOVs that the Partnership received from the LDEQ during the assessment time frame. The Partnership has taken the appropriate measures to resolve the instances of noncompliance, and will continue to work with the LDEQ with respect to the proposed Global Settlement. 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) 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.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Information
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: Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (In millions) Three Months Ended September 30, 2016: Product sales $ $ $ $ $ — $ Product sales-affiliates — Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Loss on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Goodwill $ $ — $ $ — $ $ Capital expenditures $ $ $ $ $ $ Three Months Ended September 30, 2015: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Gain on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ — $ $ — $ $ — $ Goodwill $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (In millions) Nine Months Ended September 30, 2016: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Loss on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ $ — $ — $ $ $ Goodwill $ $ — $ $ — $ $ Capital expenditures $ $ $ $ $ $ Nine Months Ended September 30, 2015: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Gain on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ — $ $ — $ $ — $ Goodwill $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ The table below presents information about segment assets as of September 30, 2016 and December 31, 2015: September 30, December 31, Segment Identifiable Assets: 2016 2015 Texas $ $ Louisiana Oklahoma Crude and Condensate Corporate Total identifiable assets $ $ 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Segment profits $ $ $ $ General and administrative expenses Gain (loss) on disposition of assets Depreciation and amortization Impairments — Operating income (loss) $ $ $ $

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Information
Supplemental Cash Flow Information	(17) Supplemental Cash Flow Information The following schedule summarizes non-cash financing activities for the period presented: Nine Months Ended September 30, 2016 2015 (In millions) Non-cash financing activities: Non-cash issuance of common units (1) $ $ — Non-cash issuance of common units of Partnership (2) — Non-cash issuance of Class C Common Units of the Partnership (2) — Installment payable, net of discount of $79.1 million (3) — (1) For the nine months ended September 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 nine months ended September 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.

Other Information

Other Information	9 Months Ended
	Sep. 30, 2016
Other Information
Other Information	(18) Other Information The following table presents additional detail for certain balance sheet captions. Other Current Liabilities Other current liabilities consisted of the following: September 30, December 31, 2016 2015 (in millions) Accrued interest $ $ Accrued wages and benefits, including taxes Accrued ad valorem taxes Capital expenditure accruals Onerous performance obligations Other Other current liabilities $ $

Significant Accounting Polici27

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
Significant Accounting Policies
Basis of Presentation	(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.
Recent Accounting Pronouncements	(b) 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 August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-15, Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 addresses the classification and presentation of certain cash receipts and cash payments related to debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, and other specific cash flow issues. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and should be applied using a retrospective transition method to each period presented. Early application is permitted, including adoption in an interim period. In September 2016, we elected to early adopt ASU 2016-15 effective January 1, 2016. The adoption had no impact on our condensed consolidated financial statements or related disclosures. (c) Accounting Standards to be Adopted in Future Periods 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 or 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. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”) , which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncements will have on our condensed consolidated financial statements and related disclosures.

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2016
Business Acquisition
Schedule of Pro Forma Information	Three Months Ended Nine Months Ended September 30, September 30, 2015 2015 Pro forma total revenues $ $ Pro forma net loss $ $ Pro forma net loss attributable to EnLink Midstream, LLC $ $ Pro forma net loss per common unit: Basic $ $ Diluted $ $
Matador
Business Acquisition
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	Purchase Price Allocation (in millions): Assets acquired: Current assets $ Property, plant and equipment Intangibles Goodwill Liabilities assumed: Current liabilities Total identifiable net assets $
Tall Oak
Business Acquisition
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	Consideration (in millions): Cash $ Issuance of common units The Partnership’s total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018 Total consideration $ Purchase Price Allocation (in millions): Assets acquired: Current assets (including $12.8 million in cash) $ Property, plant and equipment Intangibles Liabilities assumed: Current liabilities Total identifiable net assets $

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets
Schedule of Goodwill	The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions): Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (in millions) Nine Months Ended September 30, 2016 Balance, beginning of period $ $ — $ $ $ $ Impairment — — Acquisition adjustment — — — — Balance, end of period $ $ — $ $ — $ $
Schedule of Finite-Lived Intangible Assets	The following table represents the Partnership’s change in carrying value of intangible assets (in millions): Gross Net Carrying Accumulated Carrying Amount Amortization Amount Nine Months Ended September 30, 2016 Customer relationships, beginning of period $ $ $ Acquisitions — Amortization expense — Customer relationships, end of period $ $ $
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) $ 2017 2018 2019 2020 Thereafter Total $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Long-Term Debt.
Summary of debt	As of September 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions): September 30, 2016 December 31, 2015 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Partnership credit facility, due 2020 (1) $ $ — $ $ $ — $ Company credit facility, due 2019 (2) — — — — 2.70% Senior unsecured notes due 2019 7.125% Senior unsecured notes due 2022 4.40% Senior unsecured notes due 2024 4.15% Senior unsecured notes due 2025 4.85% Senior unsecured notes due 2026 — — — 5.60% Senior unsecured notes due 2044 5.05% Senior unsecured notes due 2045 Other debt — — — — Debt classified as long-term $ $ $ $ $ $ Debt issuance cost (3) Long-term debt, net of unamortized issuance cost $ $ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.2% at September 30, 2016 and 1.8% at December 31, 2015. (2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.0% at September 30, 2016. Net of amortization of $8.0 million at September 30, 2016 and $5.1 million at December 31, 2015.

Income Tax (Tables)

Income Tax (Tables)	9 Months Ended
	Sep. 30, 2016
Income Taxes
Schedule of Components of Income Tax Expense (Benefit)	Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) (in millions) ENLC income tax expense $ $ $ $ Total income tax expense $ $ $ $
Schedule of Effective Income Tax Rate Reconciliation	Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) (in millions) Tax expense (benefit) at statutory federal rate (35%) $ $ $ $ State income taxes expense (benefit), net of federal tax benefit Income tax expense from partnership Non-deductible expense related to asset impairment Other — Total income tax expense $ $ $ $

Certain Provision of the Part32

Certain Provision of the Partnership Agreement (Tables)	9 Months Ended
	Sep. 30, 2016
Certain Provision of the Partnership Agreement
Distributions Made to Limited Partner, by Distribution	A summary of the Partnership’s distribution activity relating to the common units for the nine months ended September 30, 2016 is provided below: Declaration period Distribution/unit Date paid/payable 2016 Fourth Quarter of 2015 $ February 11, 2016 First Quarter of 2016 $ May 12, 2016 Second Quarter of 2016 $ August 11, 2016 Third Quarter of 2016 $ November 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 nine months ended September 30, 2016 and 2015 (in millions): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Income allocation for incentive distributions $ $ $ $ Unit-based compensation attributable to ENLC’s restricted units General Partner share of net income (loss) — General Partner interest in drop down transactions — — — General Partner interest in net income $ $ $ $

Earnings per Unit and Dilutio33

Earnings per Unit and Dilution Computations (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings per Unit and Dilution Computations
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 nine months ended September 30, 2016 and 2015 (in millions, except per unit amounts): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 EnLink Midstream, LLC interest in net income (loss) $ $ $ $ Distributed earnings allocated to: Common units (1) (2) $ $ $ $ Unvested restricted units (1) (2) Total distributed earnings $ $ $ $ Undistributed loss allocated to: Common units $ $ $ $ Unvested restricted units Total undistributed loss $ $ $ $ Net income (loss) allocated to: Common units $ $ $ $ Unvested restricted units Total net income (loss) $ $ $ $ Basic and diluted net income (loss) per unit: Basic $ — $ $ $ Diluted $ — $ $ $ (1) Three months ended September 30, 2016 and 2015 represents a declared distribution of $0.255 per unit payable November 14, 2016 and a distribution of $0.255 per unit paid on November 13, 2015, respectively. Represents a declared distribution of $0.255 per unit payable on November 14, 2016, and distributions paid of $0.255 on August 12, 2016, May 12, 2016 and November 13, 2015, $0.25 per unit on August 14, 2015 and $0.245 per unit on May 15, 2015 for the nine months ended September 30, 2016 and 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Basic and diluted earnings per unit: Weighted average common units outstanding Diluted weighted average units outstanding: Weighted average basic common units outstanding Dilutive effect of restricted incentive units issued — — — Total weighted average diluted common units outstanding

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligations
Schedule of Change in Asset Retirement Obligation	Nine Months Ended September 30, 2016 2015 (in millions) Beginning asset retirement obligations $ $ Revisions to the fair values of existing liabilities Accretion expense Liabilities settled Ending asset retirement obligations $ $

Investment in Unconsolidated 35

Investment in Unconsolidated Affiliate (Tables)	9 Months Ended
	Sep. 30, 2016
Investment in Unconsolidated Affiliates
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 Howard Energy Fractionators Partners Total Three Months Ended September 30, 2016 Contributions (1) $ — $ $ Distributions (2) $ $ $ Equity in income $ $ $ September 30, 2015 Contributions $ — $ $ Distributions $ $ $ Equity in income $ $ $ Nine Months Ended September 30, 2016 Contributions (1) $ — $ $ Distributions (2) $ $ $ Equity in income $ $ $ September 30, 2015 Contributions $ — $ $ Distributions $ $ $ Equity in income $ $ $ (1) Contributions for the three and nine months ended September 30, 2016 include $3.2 and $32.7 million, respectively, of contributions to HEP for preferred units, which were redeemed during the third quarter 2016. (2) Distributions for the three and nine months ended September 30, 2016 include a redemption of $32.7 million of preferred units. The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions): September 30, December 31, 2016 2015 Gulf Coast Fractionators $ $ Howard Energy Partners Total investment in unconsolidated affiliates $ $

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 2016
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream, LLC Restricted Incentive Units: Units Fair Value Non-vested, beginning of period $ Granted Vested* Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ *
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 nine months ended September 30, 2016 and 2015, respectively, are provided below (in millions): Three Months Ended Nine Months Ended September 30, September 30, EnLink Midstream LLC Restricted Incentive Units: 2016 2015 2016 2015 Aggregate intrinsic value of units vested $ $ $ $ Fair value of units vested $ $ $ $
Schedule of Share Based Payment Award Other Than Stock Options Valuation Assumption	EnLink Midstream, LLC Performance Units: January 2016 February 2016 Beginning TSR Price $ $ Risk-free interest rate % % Volatility factor % % Distribution yield % %
Schedule of Nonvested Performance-based Units Activity	Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream, LLC Performance Units: Units Fair Value Non-vested, beginning of period $ Granted Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $
EnLink Midstream Partners, LP
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Cost of unit-based compensation charged to general and administrative expense $ $ $ $ Cost of unit-based compensation charged to operating expense Total amount charged to income $ $ $ $ Interest of non-controlling partners in unit-based compensation $ $ $ $ Amount of related income tax expense recognized in income $ $ $ $
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream Partners, LP Restricted Incentive Units: Units Fair Value Non-vested, beginning of period $ Granted Vested* Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $ *
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 nine months ended September 30, 2016 and 2015, respectively, is provided below (in millions): Three Months Ended Nine Months Ended September 30, September 30, EnLink Midstream Partners, LP Restricted Incentive Units: 2016 2015 2016 2015 Aggregate intrinsic value of units vested $ $ $ $ Fair value of units vested $ $ $ $
Schedule of Share Based Payment Award Other Than Stock Options Valuation Assumption	EnLink Midstream Partners, LP Performance Units: January 2016 February 2016 Beginning TSR Price $ $ Risk-free interest rate % % Volatility factor % % Distribution yield % %
Schedule of Nonvested Performance-based Units Activity	Nine Months Ended September 30, 2016 Weighted Average Number of Grant-Date EnLink Midstream Partners, LP Performance Units: Units Fair Value Non-vested, beginning of period $ Granted Forfeited Non-vested, end of period $ Aggregate intrinsic value, end of period (in millions) $

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2016
Derivatives
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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Change in fair value of derivatives $ $ $ $ Realized gain on derivatives Gain (loss) on derivative activity $ $ $ $
Fair Value of Derivative Assets and Liabilities Relating to Commodity Swaps	Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Change in fair value of derivatives $ $ $ $ Realized gain on derivatives Gain (loss) on derivative activity $ $ $ $ The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions): September 30, December 31, 2016 2015 Fair value of derivative assets — current $ $ Fair value of derivative liabilities — current Fair value of derivative liabilities — long term — Net fair value of derivatives $ $
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 September 30, 2016. The remaining term of the contracts extend no later than September 2017. September 30, 2016 Commodity Instruments Unit Volume Fair Value (In millions) NGL (short contracts) Swaps Gallons $ NGL (long contracts) Swaps Gallons Natural Gas (short contracts) Swaps MMBtu Natural Gas (long contracts) Swaps MMBtu Condensate (short contracts) Swaps MMbbls Total fair value of derivatives $
Schedule of interest rate Derivatives	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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Settlement gains on derivatives $ $ — $ $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
Fair Value Derivative Instrument	Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions): September 30, 2016 December 31, 2015 Level 2 Level 2 Commodity Swaps* $ $ Total $ $ *
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): September 30, 2016 December 31, 2015 Carrying Fair Carrying Fair Value Value Value Value Long-term debt $ $ $ $ Installment Payables $ $ $ — $ — Obligations under capital lease $ $ $ $

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Information
Company Reportable Segments	Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (In millions) Three Months Ended September 30, 2016: Product sales $ $ $ $ $ — $ Product sales-affiliates — Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Loss on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Goodwill $ $ — $ $ — $ $ Capital expenditures $ $ $ $ $ $ Three Months Ended September 30, 2015: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Gain on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ — $ $ — $ $ — $ Goodwill $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Crude and Texas Louisiana Oklahoma Condensate Corporate Totals (In millions) Nine Months Ended September 30, 2016: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Loss on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ $ — $ — $ $ $ Goodwill $ $ — $ $ — $ $ Capital expenditures $ $ $ $ $ $ Nine Months Ended September 30, 2015: Product sales $ $ $ $ $ — $ Product sales-affiliates Midstream services — Midstream services-affiliates Cost of sales Operating expenses — Gain on derivative activity — — — — Segment profit $ $ $ $ $ $ Depreciation and amortization $ $ $ $ $ $ Impairments $ — $ $ — $ $ — $ Goodwill $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $
Schedule of Segment Assets	September 30, December 31, Segment Identifiable Assets: 2016 2015 Texas $ $ Louisiana Oklahoma Crude and Condensate Corporate Total identifiable assets $ $
Reconciliation of Operating Profit (Loss) from Segments to Consolidated	September 30, December 31, Segment Identifiable Assets: 2016 2015 Texas $ $ Louisiana Oklahoma Crude and Condensate Corporate Total identifiable assets $ $ 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 Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Segment profits $ $ $ $ General and administrative expenses Gain (loss) on disposition of assets Depreciation and amortization Impairments — Operating income (loss) $ $ $ $

Supplemental Cash Flow Inform40

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Information
Schedule of Cash Flow, Supplemental Disclosures	Nine Months Ended September 30, 2016 2015 (In millions) Non-cash financing activities: Non-cash issuance of common units (1) $ $ — Non-cash issuance of common units of Partnership (2) — Non-cash issuance of Class C Common Units of the Partnership (2) — Installment payable, net of discount of $79.1 million (3) — (1) For the nine months ended September 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 nine months ended September 30, 2015, non-cash common units and Class C Common Units were issued by the Partnership as partial consideration for the Coronado acquisition. 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.

Other Information (Tables)

Other Information (Tables)	9 Months Ended
	Sep. 30, 2016
Other Information
Schedule of Other Current Liabilities	September 30, December 31, 2016 2015 (in millions) Accrued interest $ $ Accrued wages and benefits, including taxes Accrued ad valorem taxes Capital expenditure accruals Onerous performance obligations Other Other current liabilities $ $

General (Details)

General (Details)	9 Months Ended
	Sep. 30, 2016shares
EnLink Midstream Partners, LP
Business Acquisition
Units owned, limited	88,528,451
Ownership, limited (as a percent)	22.50%
Ownership, general (as a percent)	0.40%
EnLink Midstream Partners GP, LLC
Business Acquisition
Ownership, limited (as a percent)	100.00%
Tall Oak
Business Acquisition
Ownership, limited (as a percent)	16.00%

Significant Accounting Polici43

Significant Accounting Policies (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle
Other assets, noncurrent	$ 2.4	$ 2.7
Long-term debt	$ 3,245.2	3,066
ASU 2015-03
New Accounting Pronouncements or Change in Accounting Principle
Other assets, noncurrent		(23.8)
Long-term debt		$ (23.8)

Acquisition (Details)

Acquisition (Details) - USD ($) $ in Millions	Jan. 07, 2016	Nov. 16, 2015	Oct. 01, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Consideration
Issuance of common units				$ 214.9
Assets acquired
Goodwill				$ 1,542.2	$ 3,156.8	$ 2,413.9
Liabilities assumed:
Common units issued				180,048,704		164,242,160
Matador
Assets acquired
Current assets			$ 1.1
Property, plant and equipment			35.5
Intangibles			98.8
Goodwill			10.7
Liabilities assumed:
Current liabilities			(4.8)
Net assets acquired			$ 141.3
Tall Oak
Business Acquisition
Business acquisition percentage acquired	16.00%
Consideration
Cash consideration	$ 805.8
Issuance of common units	214.9
Installment payable	420.9
Installment payable discount	79.1
Total consideration	1,441.6
Assets acquired
Current assets	23
Cash Acquired from Acquisition	12.8
Property, plant and equipment	408.5
Intangibles	1,048.4
Liabilities assumed:
Current liabilities	(38.3)
Net assets acquired	$ 1,441.6
Finite-Lived Intangible Asset, Useful Life	15 years
Purchase price, first installment	$ 1,020
Business Combination, Initial Cash Consideration	$ 22.2
Business Acquisition, Transaction Costs				$ 3.7
Revenue of acquiree since acquisition				149.5
Revenue of acquiree since acquisition				(27.9)
Common Unit | Tall Oak
Liabilities assumed:
Common units issued	15,564,009
EnLink Midstream Partners, LP | Matador
Business Acquisition
Business acquisition percentage acquired			100.00%
Consideration
Total consideration			$ 141.3
Liabilities assumed:
Finite-Lived Intangible Asset, Useful Life			15 years
EnLink Midstream Partners, LP | Deadwood
Business Acquisition
Business acquisition percentage acquired		50.00%
Consideration
Total consideration		$ 40.1
Liabilities assumed:
Working capital settlement payment		$ 1.5
EnLink Midstream Partners, LP | Tall Oak
Business Acquisition
Business acquisition percentage acquired	84.00%
Consideration
Cash consideration	$ 783.6
Installment payable				420.9
Installment payable discount				$ 79.1
Liabilities assumed:
Business Combination Total Installment Payable	500
Periodic payment	$ 250				$ 250
Deferral period for a consideration payable	24 months

Acquisition (Proforma) (Details

Acquisition (Proforma) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Acquisitions
Pro forma total revenues	$ 1,205.9	$ 3,556.8
Pro forma net loss	(775.1)	(743.6)
Pro forma net loss attributable to EnLink Midstream, LLC	$ (199)	$ (176.1)
Basic	$ (1.11)	$ (0.98)
Diluted	$ (1.11)	$ (0.98)

Goodwill and Intangible Asset46

Goodwill and Intangible Assets (Goodwill) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Goodwill
Goodwill, Beginning Balance	$ 2,413.9
Impairment	(873.3)
Acquisition adjustment	(1.6)
Goodwill, Ending Balance	1,542.2
Operating Segments | Texas Operating Segment
Goodwill
Goodwill, Beginning Balance	703.5
Impairment	(473.1)
Acquisition adjustment	(1.6)
Goodwill, Ending Balance	232
Operating Segments | Oklahoma Operating Segment
Goodwill
Goodwill, Beginning Balance	190.3
Impairment	0
Goodwill, Ending Balance	190.3
Operating Segments | Crude And Condensate Segment
Goodwill
Goodwill, Beginning Balance	93.2
Impairment	(93.2)
Corporate, Non-Segment
Goodwill
Goodwill, Beginning Balance	1,426.9
Impairment	(307)
Goodwill, Ending Balance	$ 1,119.9

Goodwill and Intangible Asset47

Goodwill and Intangible Assets (Intangibles) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Assets, Accumulated Amortization	$ (142)		$ (142)		$ (54.6)
EnLink Midstream Partners, LP
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Assets, Gross	1,792.9		1,792.9		744.5
Finite-Lived Intangible Assets, Accumulated Amortization	(142)		(142)		(54.6)
Finite-Lived Intangible Assets, Net	1,650.9		1,650.9		$ 689.9
Finite-lived Intangible Assets Acquired			1,048.4
Amortization of Intangible Assets	$ (29.9)	$ (14.6)	$ (87.4)	$ (44.3)
EnLink Midstream Partners, LP | Minimum
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			10 years
EnLink Midstream Partners, LP | Maximum
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			20 years
EnLink Midstream Partners, LP | Weighted Average
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			13 years 8 months 12 days

Goodwill and Intangible Asset48

Goodwill and Intangible Assets (Amortization) (Details) - EnLink Midstream Partners, LP - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Amortization expense maturities
2016 (remaining)	$ 29.4
2,017	117.7
2,018	117.7
2,019	117.7
2,020	117.7
Thereafter	1,150.7
Total	$ 1,650.9	$ 689.9

Affiliate Transactions (Details

Affiliate Transactions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction
Due to Related Parties, Current		$ 11.2		$ 11.2		$ 14.8
Tall Oak | Devon Energy Production Company
Related Party Transaction
Minimum Volume Commitment Term	5 years
Term Of Contract	13 years
EnLink Midstream Partners, LP | Devon Energy Corporation
Related Party Transaction
Due from Affiliate, Current		76.7		76.7		110.8
Due to Related Parties, Current		$ 11.2		$ 11.2		$ 14.8
EnLink Midstream Partners, LP | Devon Energy Corporation | Customer Concentration Risk | Sales Revenue, Net
Related Party Transaction
Concentration Risk, Percentage		18.90%	16.30%	19.40%	15.90%

Long-Term Debt (Summary) (Detai

Long-Term Debt (Summary) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Jul. 14, 2016	Dec. 31, 2015
Debt Instrument
Outstanding Principal	$ 3,260.6		$ 3,076.7
Premium (Discount)	10.3		13.1
Long-Term Debt, Before Issuance Cost	3,270.9		3,089.8
Debt issuance cost	(25.7)		(23.8)
Long-term debt, net of unamortized issuance cost	3,245.2		3,066
Debt issuance cost accumulated amortization	8		5.1
Company credit facility
Debt Instrument
Outstanding Principal	23.1
Long-Term Debt, Before Issuance Cost	$ 23.1
Effective interest rate (as a percent)	3.00%
2.7% Senior Notes due 2019
Debt Instrument
Fixed interest rate (as a percent)	2.70%
Outstanding Principal	$ 400		400
Premium (Discount)	(0.3)		(0.4)
Long-Term Debt, Before Issuance Cost	$ 399.7		399.6
7.125% Senior Notes due 2022
Debt Instrument
Fixed interest rate (as a percent)	7.125%
Outstanding Principal	$ 162.5		162.5
Premium (Discount)	16.7		18.9
Long-Term Debt, Before Issuance Cost	$ 179.2		181.4
4.4% Senior Notes due 2024
Debt Instrument
Fixed interest rate (as a percent)	4.40%
Outstanding Principal	$ 550		550
Premium (Discount)	2.6		2.9
Long-Term Debt, Before Issuance Cost	$ 552.6		552.9
4.15% Senior Notes due 2025
Debt Instrument
Fixed interest rate (as a percent)	4.15%
Outstanding Principal	$ 750		750
Premium (Discount)	(1.1)		(1.2)
Long-Term Debt, Before Issuance Cost	$ 748.9		748.8
5.6% Senior Notes due 2044
Debt Instrument
Fixed interest rate (as a percent)	5.60%
Outstanding Principal	$ 350		350
Premium (Discount)	(0.2)		(0.2)
Long-Term Debt, Before Issuance Cost	$ 349.8		349.8
5.05% Senior Notes due 2045
Debt Instrument
Fixed interest rate (as a percent)	5.05%
Outstanding Principal	$ 450		450
Premium (Discount)	(6.7)		(6.9)
Long-Term Debt, Before Issuance Cost	443.3		443.1
Other debt
Debt Instrument
Outstanding Principal			0.2
Long-Term Debt, Before Issuance Cost			0.2
EnLink Midstream Partners, LP | Partnership credit facility
Debt Instrument
Outstanding Principal	75		414
Long-Term Debt, Before Issuance Cost	$ 75		$ 414
Effective interest rate (as a percent)	2.20%		1.80%
EnLink Midstream Partners, LP | 4.85% Senior Notes due 2026
Debt Instrument
Fixed interest rate (as a percent)	4.85%	4.85%
Outstanding Principal	$ 500
Premium (Discount)	(0.7)
Long-Term Debt, Before Issuance Cost	$ 499.3

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Millions	Jul. 14, 2016USD ($)	Sep. 30, 2016USD ($)itemshares	Dec. 31, 2015USD ($)
Maximum | EnLink Midstream Partners, LP
Debt Instrument
Fixed interest rate (as a percent)		7.10%	7.10%
Minimum | EnLink Midstream Partners, LP
Debt Instrument
Fixed interest rate (as a percent)		2.70%	2.70%
Company credit facility
Debt Instrument
Maximum borrowing capacity		$ 250
Units owned, limited | shares		88,528,451
Ownership, general (as a percent)		100.00%
Ownership, limited (as a percent)		100.00%
Line of credit amount outstanding		$ 23.1
Line of Credit Facility, Remaining Borrowing Capacity		$ 226.9
Company credit facility | Maximum
Debt Instrument
Leverage ratios		4.00%
Acquisition period leverage ratio		4.50%
Company credit facility | Minimum
Debt Instrument
Interest Coverage Ratio		2.50%
Company credit facility | Letter of Credit
Debt Instrument
Maximum borrowing capacity		$ 125
Company credit facility | Federal Funds
Debt Instrument
Variable rate (as a percent)		0.50%
Company credit facility | Eurodollar
Debt Instrument
Variable rate (as a percent)		1.00%
Partnership credit facility | EnLink Midstream Partners, LP
Debt Instrument
Maximum borrowing capacity		$ 1,500
Line Of Credit Facility, Additional Borrowing Limit		500
Line of credit amount outstanding		75	$ 414
Line of Credit Facility, Remaining Borrowing Capacity		$ 1,400
Number of allowed extensions | item		2
Extension period		1 year
Partnership credit facility | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Leverage ratios		5.00%
Acquisition period leverage ratio		5.50%
Conditional acquisition purchase price		$ 50
Partnership credit facility | Letter of Credit | EnLink Midstream Partners, LP
Debt Instrument
Maximum borrowing capacity		500
Letters of Credit Outstanding, Amount		$ 11
Partnership credit facility | Federal Funds | EnLink Midstream Partners, LP
Debt Instrument
Variable rate (as a percent)		0.50%
Partnership credit facility | Eurodollar | EnLink Midstream Partners, LP
Debt Instrument
Variable rate (as a percent)		1.00%
4.85% Senior Notes due 2026 | EnLink Midstream Partners, LP
Debt Instrument
Debt instrument par value	$ 500
Fixed interest rate (as a percent)	4.85%	4.85%
Selling price of debt instrument (as a percent)	99.859%
Proceeds from borrowings	$ 495.7

Income Tax (Details)

Income Tax (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Taxes
Tax expense (benefit) at statutory federal rate (35%)	$ 2	$ (67.6)	$ (158)	$ (49.5)
State income taxes expense (benefit), net of federal tax benefit	3.1	(4.8)	(11.8)	(3.5)
Income tax expense (benefit) from partnership	2.6	0.6	1.3	1.7
Non-deductible expense (recovery) related to asset impairment	(0.1)	72.3	173.8	72.3
Other		(0.3)	0.7	0.1
Income Tax Expense (Benefit)	$ 7.6	$ 0.2	$ 6	$ 21.1
Federal statutory tax rate (as a percent)			35.00%

Certain Provision of the Part53

Certain Provision of the Partnership Agreement (Details) $ / shares in Units, $ in Millions	May 13, 2016	Jan. 07, 2016shares	Jan. 31, 2016USD ($)$ / shares	Mar. 31, 2015shares	Sep. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2016$ / sharesshares	Mar. 31, 2016$ / sharesshares	Dec. 31, 2015$ / sharesshares	Sep. 30, 2016USD ($)$ / shares	Sep. 30, 2015USD ($)	Nov. 30, 2014USD ($)
Partnership agreement
Proceeds from issuance of common units									$ 110.6	$ 12.9
Proceeds from issuance of Preferred Units									$ 724.1
EnLink Midstream Partners, LP
Partnership agreement
Percentage Of Available Cash to Distribute					100.00%				100.00%
Distribution Made to Limited Partner, Distribution Period									45 days
EnLink Midstream Partners, LP | BMO EDA
Partnership agreement
Maximum sales of units under agreement											$ 350
Issuance of common units									$ 6.7
Proceeds from issuance of common units									110.6
Payments of issuance costs									1.1
Remaining sales of units under agreement					$ 205.3				$ 205.3
EnLink Midstream Partners, LP | General Partner | 13% Distribution
Partnership agreement
Incentive Distribution Percentage Levels									13.00%
Incentive Distribution, Distribution Per Unit | $ / shares									$ 0.25
EnLink Midstream Partners, LP | General Partner | 23% Distribution
Partnership agreement
Incentive Distribution Percentage Levels									23.00%
Incentive Distribution, Distribution Per Unit | $ / shares									$ 0.3125
EnLink Midstream Partners, LP | General Partner | 48% Distribution
Partnership agreement
Incentive Distribution Percentage Levels									48.00%
Incentive Distribution, Distribution Per Unit | $ / shares									$ 0.375
Common Units | EnLink Midstream Partners, LP
Partnership agreement
Distributions Declared, Per Unit | $ / shares					$ 0.39	$ 0.39	$ 0.39	$ 0.39
Class C Common Units | EnLink Midstream Partners, LP
Partnership agreement
Units issued for acquisition (in units) | shares				6,704,285
Paid in kind dividend (in units) | shares							233,107	209,044
Ratio of common units	1
Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Paid in kind dividend (in units) | shares					1,106,616	1,083,589	992,445
Ratio of common units			1
Issuance of units in private placement (in units) | shares		50,000,000
Unit purchase price (in dollars per unit) | $ / shares			$ 15
Proceeds from issuance of Preferred Units			$ 724.1
Consecutive trading period			30 days
Specified trading period			2 days
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%

Certain Provision of the Part54

Certain Provision of the Partnership Agreement (Allocation) (Details) - General Partner - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Incentive distribution
Income allocation for incentive distributions	$ 14.4	$ 13.6	$ 42.4	$ 33.7
Unit-based compensation attributable to ENLC's restricted units	(3.6)	(3.7)	(11.2)	(14.6)
General Partner share of net income (loss)		(3.6)	(2.4)	(3.3)
General Partner interest in drop down transactions				34.4
General Partner interest in net income	$ 10.8	$ 6.3	$ 28.8	$ 50.2

Earnings per Unit and Dilutio55

Earnings per Unit and Dilution Computations (Details) - USD ($) $ / shares in Units, $ in Millions	Nov. 10, 2016	Aug. 12, 2016	May 12, 2016	Nov. 13, 2015	Nov. 10, 2015	Aug. 14, 2015	May 15, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Enlink Midstream, LLC interest in net income (loss)								$ 0.7	$ (193.4)	$ (456.1)	$ (162.6)
Total distributed earnings								46.5	42.2	139	124.1
Total undistributed loss								(45.8)	$ (235.6)	$ (595.1)	$ (286.7)
Basic common unit (usd per unit)									$ (1.18)	$ (2.54)	$ (0.99)
Diluted common unit (usd per unit)									$ (1.18)	$ (2.54)	$ (0.99)
Distribution declared (usd per unit)	$ 0.255
Distribution paid (usd per unit)		$ 0.255	$ 0.255	$ 0.255	$ 0.255	$ 0.25	$ 0.245
Restricted Stock Units (RSUs)
Enlink Midstream, LLC interest in net income (loss)								(0.1)	$ (1.4)	$ (5.2)	$ (1.1)
Total distributed earnings								0.6	0.3	1.6	0.9
Total undistributed loss								(0.7)	(1.7)	(6.8)	(2)
Common Unit
Enlink Midstream, LLC interest in net income (loss)								0.8	(192)	(450.9)	(161.5)
Total distributed earnings								45.9	41.9	137.4	123.2
Total undistributed loss								$ (45.1)	$ (233.9)	$ (588.3)	$ (284.7)

Earnings per Unit and Dilutio56

Earnings per Unit and Dilution Computations (Units) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings per Unit and Dilution Computations
Weighted Average Limited Partnership Units Outstanding, Basic	180	164.2	179.6	164.2
Weighted Average Number of Shares Outstanding, Basic	180	164.2	179.6	164.2
Weighted Average Number Diluted Shares Outstanding Adjustment	1.1
Total weighted average diluted common units outstanding (in units)	181.1	164.2	179.6	164.2

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Asset retirement obligation
Asset Retirement Obligation, Beginning Balance	$ 14	$ 20.6
Revisions to the fair values of existing liabilities	(0.4)	(4)
Accretion	0.4	0.4
Liabilities settled	(0.6)	(3.2)
Asset Retirement Obligation, Ending Balance	13.4	$ 13.8
Other Noncurrent Liabilities
Asset retirement obligation
Asset Retirement Obligation, Beginning Balance	12.9
Asset Retirement Obligation, Ending Balance	13.4
Other Current Liabilities
Asset retirement obligation
Asset Retirement Obligation, Beginning Balance	1.1
Asset Retirement Obligation, Ending Balance	$ 0

Investment in Unconsolidated 58

Investment in Unconsolidated Affiliate (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Equity method investments
Contributions			$ 45	$ 8.1
Equity in income	$ 1.1	$ 6.4	(0.5)	16.1
Investment in equity investment	266.4		266.4		$ 274.3
EnLink Midstream Partners, LP
Equity method investments
Contributions	3.2	8.1	45	8.1
Distributions	37.4	12.2	52.3	31.4
Equity in income	1.1	6.4	(0.5)	16.1
Investment in equity investment	266.4		266.4		274.3
EnLink Midstream Partners, LP | Gulf Coast Fractionators
Equity method investments
Distributions	0.9	3.8	4.4	10.7
Equity in income	2.2	$ 3.4	1.1	$ 9.7
Investment in equity investment	$ 49.2		$ 49.2		52.6
Equity method investment ownership (as a percent)	38.75%	38.75%	38.75%	38.75%
EnLink Midstream Partners, LP | Howard Energy Partners
Equity method investments
Contributions	$ 3.2	$ 8.1	$ 45	$ 8.1
Distributions	36.5	8.4	47.9	20.7
Equity in income	(1.1)	$ 3	(1.6)	$ 6.4
Investment in equity investment	$ 217.2		$ 217.2		$ 221.7
Equity method investment ownership (as a percent)	31.00%	31.00%	31.00%	31.00%
Preferred Units | EnLink Midstream Partners, LP | Howard Energy Partners
Equity method investments
Contributions	$ 3.2		$ 32.7
Distributions			$ 32.7

Employee Incentive Plans (Expen

Employee Incentive Plans (Expense) (Details) - USD ($) $ in Millions	Apr. 07, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Allocation
Allocated Share-based Compensation Expense		$ 7.4	$ 7.3	$ 22.5	$ 28.9
Amount of related income tax expense recognized in income		1.7	1.8	5.4	6.5
General and Administrative
Allocation
Allocated Share-based Compensation Expense		5.8	6.3	17.7	24.9
Operating
Allocation
Allocated Share-based Compensation Expense		1.6	1	4.8	4
Non-Controlling Interest
Allocation
Allocated Share-based Compensation Expense		$ 2.7	$ 2.6	$ 8.3	$ 11.4
EnLink Midstream Partners, LP
Allocation
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

Employee Incentive Plans (RSU)

Employee Incentive Plans (RSU) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended		9 Months Ended
	Feb. 29, 2016	Jan. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (in units)		1,148,893			1,148,893
Granted (in units)					1,051,410
Vested (Units)					(339,399)
Forfeited (Units)					(53,872)
Non-vested, end of period (Units)			1,807,032		1,807,032
Aggregate intrinsic value, end of period (in millions)			$ 30.3		$ 30.3
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per unit)		$ 34.78			$ 34.78
Granted (in dollars per unit)					9.53
Vested (in dollars per unit)					36.55
Forfeited (in dollars per unit)					22.74
Non-vested, end of period (in dollars per unit)			$ 20.11		$ 20.11
Units withheld for payroll taxes on behalf of employees					96,864
Aggregate intrinsic value of units vested			$ 0.3	$ 0.1	$ 4.1	$ 8.9
Fair value of units vested			0.6	0.1	12.4	9.3
Unrecognized compensation cost related to non-vested restricted incentive units			$ 15.4		$ 15.4
Unrecognized compensation costs, weighted average period for recognition					1 year 7 months 6 days
Performance Shares
Number of Units
Non-vested, beginning of period (in units)		105,080			105,080
Granted (in units)					242,646
Forfeited (Units)					(2,525)
Non-vested, end of period (Units)			345,201		345,201
Aggregate intrinsic value, end of period (in millions)			$ 5.8		$ 5.8
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per unit)		$ 40.50			$ 40.50
Granted (in dollars per unit)					9.59
Forfeited (in dollars per unit)					41.31
Non-vested, end of period (in dollars per unit)			$ 18.76		$ 18.76
Unrecognized compensation cost related to non-vested restricted incentive units			$ 3.7		$ 3.7
Unrecognized compensation costs, weighted average period for recognition					1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price	$ 15.38	$ 15.38
Risk-free interest rate (as a percent)	0.89%	1.10%
Volatility factor (as a percent)	52.05%	46.02%
Distribution yield (as a percent)	14.00%	8.60%
Vesting Period					3 years
Minimum | Performance Shares
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					0.00%
Maximum | Performance Shares
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					200.00%
EnLink Midstream Partners, LP | Restricted Stock Units (RSUs)
Number of Units
Non-vested, beginning of period (in units)		1,253,729			1,253,729
Granted (in units)					1,058,732
Vested (Units)					(315,686)
Forfeited (Units)					(57,601)
Non-vested, end of period (Units)			1,939,174		1,939,174
Aggregate intrinsic value, end of period (in millions)			$ 34.3		$ 34.3
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per unit)		$ 29.59			$ 29.59
Granted (in dollars per unit)					10.12
Vested (in dollars per unit)					30.07
Forfeited (in dollars per unit)					21.27
Non-vested, end of period (in dollars per unit)			$ 19.13		$ 19.13
Units withheld for payroll taxes on behalf of employees					90,847
Aggregate intrinsic value of units vested			$ 0.3	0.1	$ 4.1	7.2
Fair value of units vested			0.5	$ 0.1	9.5	$ 7.6
Unrecognized compensation cost related to non-vested restricted incentive units			$ 15.8		$ 15.8
Unrecognized compensation costs, weighted average period for recognition					1 year 7 months 6 days
EnLink Midstream Partners, LP | Performance Shares
Number of Units
Non-vested, beginning of period (in units)		118,126			118,126
Granted (in units)					258,078
Forfeited (Units)					(2,798)
Non-vested, end of period (Units)			373,406		373,406
Aggregate intrinsic value, end of period (in millions)			$ 6.6		$ 6.6
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per unit)		$ 35.41			$ 35.41
Granted (in dollars per unit)					9.81
Forfeited (in dollars per unit)					36.18
Non-vested, end of period (in dollars per unit)			$ 17.71		$ 17.71
Unrecognized compensation cost related to non-vested restricted incentive units			$ 3.8		$ 3.8
Unrecognized compensation costs, weighted average period for recognition					1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price	$ 14.82	$ 14.82
Risk-free interest rate (as a percent)	0.89%	1.10%
Volatility factor (as a percent)	42.33%	39.71%
Distribution yield (as a percent)	19.20%	12.10%
Vesting Period					3 years
EnLink Midstream Partners, LP | Minimum | Performance Shares
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					0.00%
EnLink Midstream Partners, LP | Maximum | Performance Shares
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					200.00%

Derivatives (Gain Loss) (Detail

Derivatives (Gain Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivatives
Gain (loss) on derivative activity	$ (0.5)	$ 5.2	$ (6.6)	$ 6.6
EnLink Midstream Partners, LP | Commodity Swap
Derivatives
Change in fair value of derivatives	(1.6)	(0.2)	(16)	(6.4)
Realized gain on derivatives	1.1	5.4	9.4	13
Gain (loss) on derivative activity	$ (0.5)	$ 5.2	$ (6.6)	$ 6.6

Derivatives (Assets Liabilities

Derivatives (Assets Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivatives
Fair value of derivative assets - current	$ 4.3	$ 16.8
Fair value of derivative liabilities - current	(6.5)	(2.9)
Fair value of derivative liabilities - long term		(0.1)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets - current	4.3	16.8
Fair value of derivative liabilities - current	(6.5)	(2.9)
Fair value of derivative liabilities - long term		(0.1)
Net fair value of derivatives	$ (2.2)	$ 13.8

Derivatives (Notional) (Details

Derivatives (Notional) (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)MMBTUgalMMBbls	Dec. 31, 2015USD ($)
Derivatives
Fair Value	$ (2.2)	$ 13.8
Commodity Swap
Derivatives
Fair Value	(2.2)
Maximum counterparty loss	4.3
Maximum counterparty loss with netting feature	$ 1.6
Condensate | Commodity Swap | Short
Derivatives
Notional amount, volume | MMBbls	0.1
Fair Value	$ (0.4)
Natural Gas | Commodity Swap | Short
Derivatives
Notional amount, energy | MMBTU	9.3
Fair Value	$ 0.4
Natural Gas | Commodity Swap | Long
Derivatives
Notional amount, energy | MMBTU	7.1
Fair Value	$ (2.6)
NGL | Commodity Swap | Short
Derivatives
Notional amount, volume | gal	27.8
Fair Value	$ 0.8
NGL | Commodity Swap | Long
Derivatives
Notional amount, volume | gal	5.7
Fair Value	$ (0.4)

Derivatives (Interest) (Details

Derivatives (Interest) (Details) - EnLink Midstream Partners, LP - Interest Rate Swap - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Derivatives
Settlement gains on derivatives	$ 0.4	$ 0.4	$ 3.6
Fair value of derivative not designated as hedge	$ 0	$ 0

Fair Value Measurement (Recurri

Fair Value Measurement (Recurring) (Details) - EnLink Midstream Partners, LP - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value
Fair Value	$ (2.2)	$ 13.8
Level 2 | Recurring
Fair Value
Fair Value	(2.2)	13.8
Level 2 | Commodity Swap | Recurring
Fair Value
Fair Value	$ (2.2)	$ 13.8

Fair Value Measurement (Debt) (

Fair Value Measurement (Debt) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
EnLink Midstream Partners, LP
Fair Value
Senior unsecured debt	$ 3,100	$ 2,700
EnLink Midstream Partners, LP | Carrying Value
Fair Value
Long-term Debt, Fair Value	3,245.2	3,066
Installment Payable, Fair Value	459.8
Capital Lease Obligation, Fair Value	10.5	16.7
EnLink Midstream Partners, LP | Fair Value
Fair Value
Long-term Debt, Fair Value	3,124.5	2,585.5
Installment Payable, Fair Value	464.5
Capital Lease Obligation, Fair Value	$ 9.7	$ 15.6
EnLink Midstream Partners, LP | Minimum
Fair Value
Fixed interest rate (as a percent)	2.70%	2.70%
EnLink Midstream Partners, LP | Maximum
Fair Value
Fixed interest rate (as a percent)	7.10%	7.10%
Partnership credit facility | EnLink Midstream Partners, LP
Fair Value
Line of credit amount outstanding	$ 75	$ 414
Company credit facility
Fair Value
Line of credit amount outstanding	$ 23.1

Commitments and Contingencies (

Commitments and Contingencies (Details) - EnLink Midstream Partners, LP - USD ($) $ in Millions	Jul. 29, 2016	Aug. 31, 2014
Commitments and Contingencies
Environmental settlement fine	$ 0.1
Gain on Litigation Settlement		$ 6.1

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting
Product sales	$ 771	$ 863.5	$ 2,097.8	$ 2,488.8
Product sales - affiliates	43.1	40.3	99.3	89.6
Midstream services	125.7	111.3	348.5	351.3
Midstream services - affiliates	165.3	150.3	488.5	449.3
Cost of sales	(788.2)	(861.8)	(2,106.8)	(2,487.4)
Operating expenses	(98)	(105)	(296.3)	(312.6)
Gain (loss) on derivative activity	(0.5)	5.2	(6.6)	6.6
Segment profit	218.4	203.8	624.4	585.6
Depreciation and amortization	(126.2)	(98.4)	(373)	(289.1)
Impairments		(799.2)	(873.3)	(799.2)
Goodwill	1,542.2	3,156.8	1,542.2	3,156.8	$ 2,413.9
Capital expenditures	146.9	104.7	407.5	445.2
Segment identifiable assets	10,197.2		10,197.2		9,541.3
Corporate, Non-Segment
Segment Reporting
Product sales - affiliates	(99.2)	(17.6)	(209.8)	(50.3)
Midstream services - affiliates	(27)	(4.5)	(60.1)	(12.8)
Cost of sales	126.2	22.1	269.9	63.1
Gain (loss) on derivative activity	(0.5)	5.2	(6.6)	6.6
Segment profit	(0.5)	5.2	(6.6)	6.6
Depreciation and amortization	(2.4)	(1.8)	(6.8)	(5)
Impairments			(307)
Goodwill	1,119.9	1,426.9	1,119.9	1,426.9	1,426.9
Capital expenditures	8.6	3.9	15.4	10.6
Segment identifiable assets	1,471.9		1,471.9		1,751.1
Texas Operating Segment | Operating Segments
Segment Reporting
Product sales	61.3	106.9	165.7	237.3
Product sales - affiliates	81.9	35.3	191.9	91.5
Midstream services	27.5	20.3	78.1	76.2
Midstream services - affiliates	109.5	111.6	331.7	342.5
Cost of sales	(134.1)	(124.5)	(329)	(305.1)
Operating expenses	(42.9)	(44.3)	(125.2)	(136.9)
Segment profit	103.2	105.3	313.2	305.5
Depreciation and amortization	(48.7)	(44.4)	(143.6)	(123.6)
Impairments			(473.1)
Goodwill	232	1,186.8	232	1,186.8	703.5
Capital expenditures	51.8	29	132.3	183.4
Segment identifiable assets	3,195.1		3,195.1		3,709.5
Louisiana Operating Segment | Operating Segments
Segment Reporting
Product sales	430.9	399	1,118.1	1,173.6
Product sales - affiliates	24.4	17.6	47	37.4
Midstream services	57.2	63.3	165.1	184.5
Midstream services - affiliates	29.9	5.1	68.1	14.3
Cost of sales	(471.5)	(415.2)	(1,199.1)	(1,210.4)
Operating expenses	(23.5)	(27.2)	(72.2)	(78.7)
Segment profit	47.4	42.6	127	120.7
Depreciation and amortization	(28.8)	(27.4)	(86.7)	(81.8)
Impairments		(576.1)		(576.1)
Goodwill		210.7		210.7
Capital expenditures	15.4	13.5	52.2	43.4
Segment identifiable assets	2,312.6		2,312.6		2,309.3
Oklahoma Operating Segment | Operating Segments
Segment Reporting
Product sales	16.2	3.9	32.9	2.4
Product sales - affiliates	36	4.6	69.1	10.2
Midstream services	24.2	9.4	57.3	29.9
Midstream services - affiliates	47.7	34.5	134.4	94.7
Cost of sales	(58.3)	(9.4)	(109.2)	(14.6)
Operating expenses	(12.6)	(7.2)	(37.2)	(23.3)
Segment profit	53.2	35.8	147.3	99.3
Depreciation and amortization	(35.6)	(11.9)	(104.2)	(37.2)
Goodwill	190.3	190.3	190.3	190.3	190.3
Capital expenditures	58.3	19.7	190.6	37.2
Segment identifiable assets	2,451.8		2,451.8		873.4
Crude And Condensate Segment | Operating Segments
Segment Reporting
Product sales	262.6	353.7	781.1	1,075.5
Product sales - affiliates		0.4	1.1	0.8
Midstream services	16.8	18.3	48	60.7
Midstream services - affiliates	5.2	3.6	14.4	10.6
Cost of sales	(250.5)	(334.8)	(739.4)	(1,020.4)
Operating expenses	(19)	(26.3)	(61.7)	(73.7)
Segment profit	15.1	14.9	43.5	53.5
Depreciation and amortization	(10.7)	(12.9)	(31.7)	(41.5)
Impairments		(223.1)	(93.2)	(223.1)
Goodwill		142.1		142.1	93.2
Capital expenditures	12.8	$ 38.6	17	$ 170.6
Segment identifiable assets	$ 765.8		$ 765.8		$ 898

Segment Information (Reconcilia

Segment Information (Reconciliation) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Information
Segment profits	$ 218.4	$ 203.8	$ 624.4	$ 585.6
General and administrative expenses	(29.3)	(34.8)	(94.7)	(105.6)
Loss on disposition of assets	3	(3.2)	2.9	(3.2)
Depreciation and amortization	(126.2)	(98.4)	(373)	(289.1)
Impairments		(799.2)	(873.3)	(799.2)
Operating income (loss)	$ 65.9	$ (731.8)	$ (713.7)	$ (611.5)

Supplemental Cash Flow Inform70

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	Jan. 07, 2016	Sep. 30, 2016	Sep. 30, 2015
Tall Oak
Noncash Transactions
Installment payable	$ 420.9
Installment payable discount	79.1
Tall Oak | EnLink Midstream Partners, LP
Noncash Transactions
Installment payable		$ 420.9
Installment payable discount		79.1
Periodic payment	$ 250		$ 250
Common Units | Tall Oak
Noncash Transactions
Units issued (in units)		$ 214.9
Common Units | Coronado | EnLink Midstream Partners, LP
Noncash Transactions
Units issued (in units)			180
Class C Common Units | Coronado | EnLink Midstream Partners, LP
Noncash Transactions
Units issued (in units)			$ 180

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Other Information
Accrued interest	$ 58.1	$ 23.2
Accrued wages and benefits, including taxes	13.7	27.7
Accrued ad valorem taxes	32.9	27
Capital expenditure accruals	35.3	22.3
Onerous performance obligations	16.1	17
Other	40.2	57.6
Other current liabilities	$ 196.3	$ 174.8