EnLink Midstream Partners (ENLK) 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
Document And 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 PARTNERS, LP
Entity Central Index Key	1,179,060
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		339,896,417

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 60	$ 5.9
Accounts receivable:
Trade, net of allowance for bad debt of $0.8 and $0.3, respectively	47.8	37.5
Accrued revenue and other	311.9	268.7
Related party	76.7	111.1
Fair value of derivative assets	4.3	16.8
Natural gas and NGLs inventory, prepaid expenses and other	38.1	32.1
Total current assets	538.8	472.1
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	422.3	987
Investment in unconsolidated affiliates	266.4	274.3
Other assets, net	2.4	2.7
Total assets	9,075.9	8,092.8
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	196.2	174.4
Total current liabilities	762.8	432
Long-term debt	3,222.8	3,066.8
Fair value of derivative liabilities		0.1
Asset retirement obligation	13.4	12.9
Installment payable, net of discount of $32.8	217.2
Other long-term liabilities	49.6	65.9
Deferred tax liability	73.2	73.6
Redeemable non-controlling interest	6.2	7
Partners' equity:
Preferred unitholders (52,076,035 units issued and outstanding at September 30, 2016)	773.3
General partner interest (1,594,974 equivalent units outstanding at September 30, 2016 and December 31, 2015	209.7	213.4
Non-controlling interest	422	15.9
Total partners’ equity	4,730.7	4,434.5
Commitments and contingencies (Note 13)
Total liabilities and partners’ equity	9,075.9	8,092.8
Common Unit
Partners' equity:
Limited partners' unitholders	$ 3,325.7	4,055.8
Class C Common Units
Partners' equity:
Limited partners' unitholders		$ 149.4

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Assets [Abstract]
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 [Abstract]
Current installment payable discount	7.4
Noncurrent installment payable discount	$ 32.8
Partners' equity:
Common Units, Issued	339,531,171	339,531,171
Common Units, Outstanding	325,090,624	325,090,624
Class C Common Units, Issued		7,075,433
Class C Common Units, Outstanding		7,075,433
Preferred Units, Issued	52,076,035
Preferred Units, Outstanding	52,076,035
General Partners' Capital Account, Units Issued	1,594,974	1,594,974

Consolidated Statements of Oper

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)	28.3	33.5	90.6	102.3
(Gain) 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	566.3	799.2
Total operating costs and expenses	1,037.7	1,901.1	3,430.1	3,993.8
Operating income (loss)	66.9	(730.5)	(402.6)	(608.2)
Other income (expense):
Interest expense, net of interest income	(48)	(30.2)	(137.9)	(71.5)
Income (loss) from unconsolidated affiliates	1.1	6.4	(0.5)	16.1
Other income	0.1	0.1	0.1	0.7
Total other expense	(46.8)	(23.7)	(138.3)	(54.7)
Income (loss) before non-controlling interest and income taxes	20.1	(754.2)	(540.9)	(662.9)
Income tax provision	(2.6)	(1)	(1.3)	(2.9)
Net income (loss)	17.5	(755.2)	(542.2)	(665.8)
Net loss attributable to the non-controlling interest	(1.3)	(0.3)	(5.6)	(0.3)
Net income (loss) attributable to EnLink Midstream Partners, LP	18.8	(754.9)	(536.6)	(665.5)
General partner interest in net income	10.8	6.3	28.8	50.2
Limited partners’ interest in net loss attributable to EnLink Midstream Partners, LP	(11.4)	(745.2)	(602.1)	(700.5)
Class C partners’ interest in net loss attributable to EnLink Midstream Partners, LP		$ (16)	(12.5)	$ (15.2)
Preferred interest in net income attributable to EnLink Midstream Partners, LP	$ 19.4		$ 49.2
Net loss attributable to EnLink Midstream Partners, LP per limited partners’ unit:
Basic income (loss) (in dollars per unit)	$ (0.03)	$ (2.32)	$ (1.82)	$ (2.38)
Diluted income (loss) (in dollars per unit)	$ (0.03)	$ (2.32)	$ (1.82)	$ (2.38)

Condensed Consolidated Statemen

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	28.3	33.5	90.6	102.3
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		$ 0.2

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners Equity - Partners Equity - 9 months ended Sep. 30, 2016 - USD ($) shares in Millions, $ in Millions	Common UnitLimited PartnerDevon	Common UnitLimited Partner	Class C Common UnitsLimited Partner	Preferred Units	General Partner	Noncontrolling InterestENLC	Noncontrolling Interest	ENLC	Devon	Total
Beginning Balance at Dec. 31, 2015		$ 4,055.8	$ 149.4		$ 213.4		$ 15.9			$ 4,434.5
Balance (Units) at Dec. 31, 2015		325.2	7.1		1.6
Increase (Decrease) in Partners' Capital
Issuance of common units		$ 110.6								110.6
Issuance of common units (in units)		6.7
Issuance of Preferred Units				$ 724.1						724.1
Issuance of units in private placement (in units)				50
Contributions	$ 1.4					$ 237.1		$ 237.1	$ 1.4
Conversion of restricted units for common units, net of units withheld for taxes		$ (1.2)								(1.2)
Conversion of restricted units for common units, net of units withheld for taxes (units)		0.2
Unit-based compensation		$ 11.3			$ 11.2					22.5
Distributions		(387)			(43.7)					(430.7)
Distributions (in units)			0.4	2.1
Conversion of Class C Common Units to common units		$ 136.9	$ (136.9)
Conversion of Class C Common Units to common units (in units)		7.5	(7.5)
Non-controlling interest contributions							179.4			179.4
Distributions to non-controlling interest							(4.8)			(4.8)
Net income (loss)		$ (602.1)	$ (12.5)	$ 49.2	28.8		(5.6)			(542.2)
Ending Balance at Sep. 30, 2016		$ 3,325.7		$ 773.3	$ 209.7		$ 422			$ 4,730.7
Balance (Units) at Sep. 30, 2016		339.6		52.1	1.6

Consolidated Statements of Cha7

Consolidated Statements of Changes in Partners Equity - Redeemable Non-controlling Interest - 9 months ended Sep. 30, 2016 - USD ($) $ in Millions	Redeemable Noncontrolling Interest	Total
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2015	$ 7
Increase (Decrease) in Temporary Equity
Distributions to non-controlling interest	(0.8)	$ (4.8)
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
Net Cash Provided by (Used in) Operating Activities, Continuing Operations [Abstract]
Net loss	$ (542.2)	$ (665.8)
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities
Impairments	566.3	799.2
Depreciation and amortization	373	289.1
Accretion expense	0.4	0.4
(Gain) loss on disposition of assets	(2.9)	3.2
Non-cash unit-based compensation	22.5	28.6
Deferred tax benefit	(0.3)
(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	2.6	2.2
Amortization of net (premium) discount 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	(17.6)	124.3
Natural gas and NGLs inventory, prepaid expenses and other	3.6	(18.4)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	49.3	(58)
Net cash provided by operating activities	509.2	508
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(423.7)	(450.3)
Proceeds from insurance settlement	0.3
Acquisition of business, net of cash acquired	(769.3)	(330.6)
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	(1,181.4)	(774.3)
Cash flows from financing activities:
Proceeds from borrowings	1,629.3	2,604.4
Payments on borrowings	(1,469.2)	(1,773.2)
Payments on capital lease obligations	(3.2)	(2.5)
Decrease in drafts payable		(12.6)
Debt refinancing costs	(4.6)	(9.5)
Conversion of restricted units, net of units withheld for taxes	(1.2)	(2.5)
Proceeds from issuance of common units	110.6	12.9
Proceeds from issuance of Preferred Units	724.1
Distributions to non-controlling partners	(5.6)	(66.5)
Contributions by non-controlling partners (including contributions from affiliates of $27.9 million)	179.4	12.2
Distribution to partners	(430.7)	(338.9)
Mandatorily redeemable non-controlling interest	(4)
Contributions from Devon	1.4	28.8
Distribution to Devon for net assets acquired		(171)
Net cash provided by financing activities	726.3	281.6
Net increase in cash and cash equivalents	54.1	15.3
Cash and cash equivalents, beginning of period	5.9	9.6
Cash and cash equivalents, end of period	60	24.9
Cash paid for interest	70.4	45.5
Cash paid for income taxes	$ 2.5	$ 0.4

Consolidated Statements of Cas9

Consolidated Statements of Cash Flows (Parenthetical) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Contributions by non-controlling partners
Contributions by non-controlling partners	$ 179.4
Affiliates
Contributions by non-controlling partners
Contributions by non-controlling partners	$ 27.9

General

General	9 Months Ended
	Sep. 30, 2016
General
General	(1) General In this report, the term “Partnership,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership (as defined below) 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) Organization of Business EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership. EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC’s managing member and common units which represent approximately 64% of the outstanding limited liability company interests in ENLC. Effective as of January 7, 2016, the Operating Partnership acquired 84% of the outstanding equity interests in EnLink Oklahoma T.O., and ENLC acquired the remaining 16% equity interests in EnLink Oklahoma T.O. Since we control EnLink Oklahoma T.O., we reflect our ownership in EnLink Oklahoma T.O. on a consolidated basis and ENLC’s ownership is reflected as a non-controlling interest in the respective condensed consolidated financial statements and related disclosures. On August 1, 2016, we formed a joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, L.P. (“NGP”) to operate and expand our natural gas, natural gas liquids (“NGLs”) and crude oil midstream assets in the liquids-rich Delaware Basin. The Delaware Basin JV is owned 50.1 percent by us and 49.9 percent by NGP. Since we control the Delaware Basin JV, we reflect our ownership in the Delaware Basin JV on a consolidated basis, and NGP’s ownership is reflected as a non-controlling interest in the respective condensed consolidated financial statements and related disclosures. (b) Nature of Business We primarily focus 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. We connect the wells of producers in our market areas to our gathering systems, process natural gas to remove NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide 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. We also have crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. Our 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. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Our 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. Our processing plants remove NGLs and CO 2 from a natural gas stream, and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

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, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC’s control of us through its ownership and control of our general partner and Devon’s control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our 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 our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and 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 we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner. (b) Adopted Accounting Standards In January 2016, we adopted Accounting Standards Update (“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 $23.0 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 January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update had no impact on our condensed consolidated financial statements or related disclosures. In January 2016, we adopted ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements or related disclosures. 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 Accounting Standards Codification (“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 we expect 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 our 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, we 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 $ We 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 our Texas segment and is non-deductible for tax purposes. Deadwood Acquisition Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, we 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 ENLC acquired an 84% and 16% 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 us 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 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 us, 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 ENLC and approximately $22.2 million in cash paid by ENLC. 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 $ Total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018 Contribution from ENLC 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 (in millions) Pro forma total revenues $ $ Pro forma net loss $ $ Pro forma net loss attributable to EnLink Midstream Partners, LP $ $ 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 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 perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate 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 determined that the estimated fair values of our Texas and Crude and Condensate reporting units were less than their respective carrying amounts, primarily related to increases in our discount rate subsequent to year-end. The second step of the goodwill impairment test measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized for the three months ended March 31, 2016, which is included in our nine months ended September 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations. We concluded that the fair value of goodwill of our 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 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 assumptions and estimates, or our assumptions and estimates change due to new information, we 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 value of our Texas reporting unit may be impacted in the future by a further decline in our unit price or a continuing prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our Texas reporting unit. 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 our 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 our 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 We engage 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 us. Devon accounted for 18.9% and 19.4% of our 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. We 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, we 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) $ $ — $ $ $ — $ 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 (2) 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) Net of amortization of $7.3 million and $4.7 million at September 30, 2016 and December 31, 2015, respectively. Credit Facility We have a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility that matures on March 6, 2020. Under our credit facility, we are permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under our 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 our credit facility by one year on each occasion. Our credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in our credit facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters. Borrowings under our credit facility bear interest at our 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 our credit rating. If we breach certain covenants governing our credit facility, amounts outstanding under our 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 our 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 our credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in our Annual Report on Form 10-K for the year ended December 31, 2015. We expect 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, we issued $500.0 million in aggregate principal amount of our 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 our revolving credit facility and for general partnership purposes.

Partners Capital

Partners Capital	9 Months Ended
	Sep. 30, 2016
Partners' Capital
Partners' Capital	(7) Partners’ Capital (a) Issuance of Common Units In November 2014, we 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 our common units from time to time through an “at the market” equity offering program. We 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. We have 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, we 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). We 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) Class C Common Units In March 2015, we 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 our 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 our 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 were converted into common units on a one-for-one basis on May 13, 2016. (c) Preferred Units In January 2016, we issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (the “Preferred Units”) representing our 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 our 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 our 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 our 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 our general partner or the managing member of ENLC, 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 10, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the three and nine months ended September 30, 2016, $19.4 million and $49.2 million of income was allocated to the Preferred Units, respectively. (d) Distributions Unless restricted by the terms of our credit facility and/or the indentures governing our senior unsecured notes, we must make distributions of 100% of available cash, as defined in our agreement, within 45 days following the end of each quarter. Distributions are made to our 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. Our general partner is not entitled to its general partner or incentive distributions with respect to the Preferred Units issued in kind. Our general partner owns the general partner interest in us and all of our incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.0% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48.0% of amounts we distribute in excess of $0.375 per unit. A summary of the 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 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) Earnings per Unit and Dilution Computations As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income (loss) attributable to drop down interests acquired during 2015 from ENLC and Devon for periods prior to acquisition is not allocated to the limited partners for purposes of calculating net income (loss) per common unit. The following table reflects the computation of basic and diluted earnings per limited partner unit for the period presented (in millions, except per unit amounts): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Limited partners’ 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 limited partners’ interest in 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 $0.39 per unit payable on November 11, 2016 and a distribution of $0.39 per unit paid on November 12, 2015, respectively. (2) Represents a declared distribution of $0.39 per unit payable on November 11, 2016, and distributions paid of $0.39 per unit on August 11, 2016, $0.39 per unit on May 12, 2016, $0.39 per unit on November 12, 2015, $0.385 per unit on August 13, 2015, and $0.38 per unit on May 14, 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 limited partner unit for the periods presented (in millions): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding Dilutive effect of restricted units issued — — — — Total weighted average limited partner diluted common units outstanding (1) The nine months ended September 30, 2016 includes the weighted average impact of 3,645,688 Common Class C Common Units that converted into common units on May 13, 2016. The three and nine months ended September 30, 2015 includes the weighted average impact of 6,867,012 and 4,939,219 Common Class C Common Units, respectively, that converted into common units on May 13, 2016 and 13,537,133 and 9,258,104 Common Class E Common Units, respectively, that converted into common units on August 3, 2015. 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. All common unit equivalents were antidilutive for the three and nine months ended September 30, 2016 and 2015 because the limited partners were allocated a net loss. Net income is allocated to our general partner in an amount equal to its incentive distributions as described in (d) above. Our 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 our net income adjusted for ENLC’s unit-based compensation specifically allocated to our general partner. The net income allocated to our general partner is as follows for the periods presented (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 $ $ $ $

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation.
Asset Retirement Obligation	(8) Asset Retirement Obligations The schedule below summarizes the changes in our 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 affiliate	(9) Investment in Unconsolidated Affiliates Our 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 our 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 our 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	(10) Employee Incentive Plans (a) Long-Term Incentive Plans We account 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, our 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 common units of the Partnership 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. We and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to our officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us 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 $ $ $ $ (b) EnLink Midstream Partners, LP Restricted Incentive Units Our 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) $ * Vested units include 90,847 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and 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) EnLink Midstream Partners, LP Performance Units In 2016, our 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 us and ENLC (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 our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group; and (iv) the distribution yield. The fair value of the 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 our 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 our non-vested performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years. (d) EnLink Midstream, LLC Restricted Incentive Units ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the 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) $ * Vested units include 96,864 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and 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) EnLink Midstream, LLC’s Performance Units In 2016, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions: EnLink Midstream, LLC Performance Units: January 2016 February 2016 Beginning TSR Price $ $ Risk-free interest rate % % Volatility factor % % Distribution yield % % The following table presents a summary of ENLC’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	(11) Derivatives Commodity Swaps We manage our 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. We do 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 our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts. We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our 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 we receive a percentage of liquids as a fee for processing third-party gas or where we receive 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 our business and (3) where we are 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 our 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. We estimate the fair value of all of our 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 we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have 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 our counterparties failed to perform under existing swap contracts, our 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 We entered into interest rate swaps during April and May 2015 in connection with the issuance of the 2025 Notes in May 2015. Additionally, we entered into interest rate swaps during July 2016 in connection with the issuance of the 2026 Notes in July 2016. We have 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	(12) 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. Our 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 $ $ * The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our and/or the counterparty credit risk as required under FASB ASC 820. Fair Value of Financial Instruments We have determined the estimated fair value of our 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 we 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 our cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. We had $75.0 million and $414.0 million in outstanding borrowings under our revolving credit facility as of September 30, 2016 and December 31, 2015, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. Under senior unsecured notes we had total borrowings of $3.1 billion and $2.7 billion as of September 30, 2016 and December 31, 2015, 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	(13) Commitments and Contingencies (a) Severance and Change in Control Agreements Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with our 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 our general partner or its affiliates or interfering with a client or customer of our general partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment. (b) Environmental Issues The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we 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 our results of operations, financial condition or cash flows. In February 2016, a spill occurred at our Kill Buck Station in our 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. We do 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 our operational control of E2 Appalachian Compression, LLC in and preparation to commence operational control of E2 Ohio Compression, LLC, we 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”). We 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 yet have information concerning any fine or penalty that may be assessed, we do not believe any such fine or penalty will be material to our operations. On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of our Louisiana operations, we 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 our assessment, which involved several of our 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 our assessment as well as noncompliance that was the subject of notices of potential violations and NOVs that we received from the LDEQ during the assessment time frame. We have taken the appropriate measures to resolve the instances of noncompliance, and we will continue to work with the LDEQ with respect to the proposed Global Settlement. Additionally, although the spill that previously occurred in our West Virginia operations in the third quarter of 2015 is still pending, we do not believe that any fine or penalty that may be issued will be material to our operations. Lastly, we continue to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. (c) Litigation Contingencies We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows. At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time we (or our subsidiaries) are a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our 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, we do not expect that awards in these matters will have a material adverse effect on our financial position, results of operations or cash flows. We (or our subsidiaries) are defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed, owned or operated by us as part of our 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. Our 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. We intend to continue vigorously defending the case. The success of the plaintiffs’ appeal as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable. We own and operate 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 our facilities. We are seeking to recover our losses from responsible parties. We have sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses. We have 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. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and have also sued our insurers. In August 2014, we received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties. In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, 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 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable. We intend to vigorously defend the case. We have also filed a claim for defense and indemnity with our insurers.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Information
Segment Information	(14) Segment Information Identification of the majority of our operating segments is based principally upon geographic regions served. Our 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. Our 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. We evaluate the performance of our operating segments based on operating revenues and segment profits. Summarized financial information concerning our 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	(15) 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: Installment payable, net of discount of $79.1 million (1) $ $ — Non-cash issuance of common units (2) — Non-cash issuance of Class C Common Units (2) — Contribution from ENLC (3) — Non-cash adjustment of interest in Midstream Holdings (4) — (1) We 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. (2) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. (3) Contribution from ENLC in connection with the acquisition of Tall Oak. See Note 3 - Acquisitions for further discussion. (4) Non-cash adjustment to reflect recast of the interests in EnLink Midstream Holdings, LP acquired on February 17, 2015.

Other Information

Other Information	9 Months Ended
	Sep. 30, 2016
Other Information
Other Information	(16) 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 Policy (

Significant Accounting Policy (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, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC’s control of us through its ownership and control of our general partner and Devon’s control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our 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 our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and 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 we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner.
Recent Accounting Pronouncements	(b) Adopted Accounting Standards In January 2016, we adopted Accounting Standards Update (“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 $23.0 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 January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update had no impact on our condensed consolidated financial statements or related disclosures. In January 2016, we adopted ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements or related disclosures. 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 Accounting Standards Codification (“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 we expect 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 our 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.

Acquisition (Tables)

Acquisition (Tables)	9 Months Ended
	Sep. 30, 2016
Business Acquisition
Business Acquisition, Pro Forma Information	Three Months Ended Nine Months Ended September 30, September 30, 2015 2015 (in millions) Pro forma total revenues $ $ Pro forma net loss $ $ Pro forma net loss attributable to EnLink Midstream Partners, LP $ $ Pro forma net loss per common unit: Basic $ $ Diluted $ $
Matador
Business Acquisition
Schedule of 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 Assets Acquired and Liabilities Assumed	Consideration (in millions): Cash $ Total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018 Contribution from ENLC 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	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 our 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 our 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) $ $ — $ $ $ — $ 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 (2) 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. Net of amortization of $7.3 million and $4.7 million at September 30, 2016 and December 31, 2015, respectively.

Partners Capital (Tables)

Partners Capital (Tables)	9 Months Ended
	Sep. 30, 2016
Partners' Capital
Distributions Made to Limited Partner, by Distribution	A summary of the 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 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 Earnings Per Unit	The following table reflects the computation of basic and diluted earnings per limited partner unit for the period presented (in millions, except per unit amounts): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Limited partners’ 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 limited partners’ interest in 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 $0.39 per unit payable on November 11, 2016 and a distribution of $0.39 per unit paid on November 12, 2015, respectively. (2) Represents a declared distribution of $0.39 per unit payable on November 11, 2016, and distributions paid of $0.39 per unit on August 11, 2016, $0.39 per unit on May 12, 2016, $0.39 per unit on November 12, 2015, $0.385 per unit on August 13, 2015, and $0.38 per unit on May 14, 2015 for the nine months ended September 30, 2016 and 2015.
Schedule of Weighted Average Units	The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions): Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Basic weighted average units outstanding: Weighted average limited partner basic common units outstanding (1) Diluted weighted average units outstanding: Weighted average limited partner basic common units outstanding Dilutive effect of restricted units issued — — — — Total weighted average limited partner diluted common units outstanding The nine months ended September 30, 2016 includes the weighted average impact of 3,645,688 Common Class C Common Units that converted into common units on May 13, 2016. The three and nine months ended September 30, 2015 includes the weighted average impact of 6,867,012 and 4,939,219 Common Class C Common Units, respectively, that converted into common units on May 13, 2016 and 13,537,133 and 9,258,104 Common Class E Common Units, respectively, that converted into common units on August 3, 2015.
Incentive Distributions	The net income allocated to our general partner is as follows for the periods presented (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 $ $ $ $

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation.
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 32

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 our 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 our 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 Plan (Tables

Employee Incentive Plan (Tables)	9 Months Ended
	Sep. 30, 2016
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 $ $ $ $
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) $ * Vested units include 90,847 units withheld for payroll taxes paid on behalf of employees.
Schedule of Share Based Compensation Restricted Stock and Restricted Stock Units Vested and Fair Value Vested	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and 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 Unit-based Fair Value Assumptions	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) $
ENLC
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) $ * Vested units include 96,864 units withheld for payroll taxes paid on behalf of employees.
Schedule of Share Based Compensation Restricted Stock and Restricted Stock Units Vested and Fair Value Vested	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 Unit-based Fair Value Assumptions	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) $

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	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 $ $ * The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our and/or the counterparty credit risk as required under FASB ASC 820.
Fair Value Financial Instrument	Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we 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
Schedule of reportable segment	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 Financial Statement	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 Inform37

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Information
Schedule of Supplemental Cash Flow	Nine Months Ended September 30, 2016 2015 (In millions) Non-cash financing activities: Installment payable, net of discount of $79.1 million (1) $ $ — Non-cash issuance of common units (2) — Non-cash issuance of Class C Common Units (2) — Contribution from ENLC (3) — Non-cash adjustment of interest in Midstream Holdings (4) — (1) We 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. (2) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. (3) Contribution from ENLC in connection with the acquisition of Tall Oak. See Note 3 - Acquisitions for further discussion. Non-cash adjustment to reflect recast of the interests in EnLink Midstream Holdings, LP acquired on February 17, 2015.

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, 2016	Aug. 01, 2016	Jan. 07, 2016
Tall Oak
Business Acquisition
Business acquisition percentage acquired			84.00%
Tall Oak | ENLC
Business Acquisition
Business acquisition percentage acquired			16.00%
Devon
Business Acquisition
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	64.00%
Delaware Basin JV
Business Acquisition
Equity method investment ownership (as a percent)		50.10%
Delaware Basin JV | NGP
Business Acquisition
Equity method investment ownership (as a percent)		49.90%

Significant Accounting Polici40

Significant Accounting Policies (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Policies
Other assets, net	$ 2.4	$ 2.7
Long-term debt	$ 3,222.8	3,066.8
ASU 2015-03
Policies
Other assets, net		(23)
Long-term debt		$ (23)

Acquisition (Details)

Acquisition (Details) - USD ($) $ in Millions	Jan. 07, 2016	Nov. 16, 2015	Oct. 01, 2015	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Assets acquired
Goodwill				$ 422.3	$ 422.3	$ 987	$ 1,729.9
Matador
Business Acquisition
Business acquisition percentage acquired			100.00%
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
Finite-Lived Intangible Asset, Useful Life			15 years
Consideration
Total consideration			$ 141.3
Deadwood Acquisition
Business Acquisition
Business acquisition percentage acquired		50.00%
Liabilities assumed
Working capital settlement payment		$ 1.5
Consideration
Total consideration		$ 40.1
Tall Oak
Business Acquisition
Business acquisition percentage acquired	84.00%
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, Total Installment Payable	500
Consideration payable deferrable	$ 250
Deferral period for a consideration payable	24 months
Consideration
Cash	$ 783.6
Total installment payable, net of discount	420.9			420.9
Installment payable discount	79.1			79.1	79.1		$ 79.1
Total consideration	$ 1,441.6
Business Acquisition, Transaction Costs				3.7	3.7
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual					149.5
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual					$ 27.9
Devon
Consideration
Contribution from ENLC				$ 1.4
ENLC | Tall Oak
Business Acquisition
Business acquisition percentage acquired	16.00%
Liabilities assumed
Equity issued for acquisition (in units)	15,564,009
Equity issued for acquisition	$ 22.2
Consideration
Contribution from ENLC	$ 237.1

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	$ 3,556.7
Pro forma net loss	(775.9)	(727.8)
Pro forma net los attributable to EnLink Midstream Partners, LP	$ (772.7)	$ (718.1)
Basic	$ (2.34)	$ (2.49)
Diluted	$ (2.34)	$ (2.49)

Goodwill and Intangible Asset43

Goodwill and Intangible Assets (Goodwill) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016
Goodwill
Goodwill, beginning of period	$ 987	$ 987
Impairment	(566.3)	(566.3)
Acquisition adjustment		1.6
Goodwill, end of period		422.3
Operating Segments | Texas Operating Segment
Goodwill
Goodwill, beginning of period	703.5	703.5
Impairment		(473.1)
Acquisition adjustment		1.6
Goodwill, end of period		232
Operating Segments | Louisiana Operating Segment
Goodwill
Acquisition adjustment		0
Operating Segments | Oklahoma Operating Segment
Goodwill
Goodwill, beginning of period	190.3	190.3
Impairment		0
Acquisition adjustment		0
Goodwill, end of period		190.3
Operating Segments | Crude And Condensate Segment
Goodwill
Goodwill, beginning of period	$ 93.2	93.2
Impairment		(93.2)
Acquisition adjustment		0
Corporate
Goodwill
Acquisition adjustment		$ 0

Goodwill and Intangible Asset44

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, Gross	$ 1,792.9		$ 1,792.9		$ 744.5
Finite-Lived Intangible Assets, Accumulated Amortization	(142)		(142)		(54.6)
Total	1,650.9		1,650.9		$ 689.9
Finite-Lived Intangibles Assets Acquired			1,048.4
Amortization of Intangible Assets	$ (29.9)	$ (14.6)	$ (87.4)	$ (44.3)
Minimum
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			10 years
Maximum
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			20 years
Weighted Average
Acquired Finite-Lived Intangible Assets
Finite-Lived Intangible Asset, Useful Life			13 years 8 months 12 days

Goodwill and Intangible Asset45

Goodwill and Intangible Assets (Amortization) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Summary of estimated amortization expense
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	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction
Accounts payable to related party	$ 11.2		$ 11.2		$ 14.8
Devon
Related Party Transaction
Due from Affiliate, Current	76.7		76.7		110.8
Accounts payable to related party	$ 11.2		$ 11.2		$ 14.8
Sales Revenue, Net | Customer Concentration Risk | Devon
Related Party Transaction
Concentration Risk, Percentage	18.90%	16.30%	19.40%	15.90%
Tall Oak | DEPC
Related Party Transaction
Minimum Volume Commitment			5 years
Term Of Contract			13 years

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	$ 3,237.5		$ 3,076.7
Premium (Discount)	10.3		13.1
Long-Term Debt, Before Issuance Cost	3,247.8		3,089.8
Debt issuance cost	(25)		(23)
Long-term debt, net of unamortized issuance cost	$ 3,222.8		$ 3,066.8
Effective interest rate (as a percent)	2.20%		1.80%
Debt issuance cost accumulated amortization	$ 7.3		$ 4.7
Credit Facility
Debt Instrument
Outstanding Principal	75		414
Long-Term Debt, Before Issuance Cost	$ 75		414
2.70% 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
4.40% 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
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
5.60% 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

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Millions	Jul. 14, 2016USD ($)	Sep. 30, 2016USD ($)item	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Debt Instrument
Line of credit amount outstanding		$ 75		$ 414
Proceeds from borrowings		$ 1,629.3	$ 2,604.4
Minimum
Debt Instrument
Fixed interest rate (as a percent)		2.70%
Maximum
Debt Instrument
Fixed interest rate (as a percent)		7.10%
Credit Facility
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,500
Line Of Credit Facility, Additional Borrowing Limit		$ 500
Number of allowed extensions | item		2
Extension period		1 year
Leverage ratios		5
Letters of Credit Outstanding, Amount		$ 11
Line of credit amount outstanding		75
Line of Credit Facility, Remaining Borrowing Capacity		$ 1,400
Credit Facility | Maximum
Debt Instrument
Leverage ratios		5.5
Conditional acquisition purchase price		$ 50
Credit Facility | Federal Funds
Debt Instrument
Variable interest rate (as a percent)		0.50%
Credit Facility | Eurodollar
Debt Instrument
Variable interest rate (as a percent)		1.00%
Credit Facility | Letter of Credit
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity		$ 500
4.85% Senior Notes due 2026
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

Partners Capital (Details)

Partners Capital (Details) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended				9 Months Ended		12 Months Ended
	Jan. 31, 2016USD ($)$ / sharesshares	Mar. 31, 2015shares	Sep. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2016$ / sharesshares	Mar. 31, 2016$ / sharesshares	Dec. 31, 2015$ / shares	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)	Dec. 31, 2015shares	May 13, 2016	Nov. 30, 2014USD ($)
Partners' capital
Issuance of common units							$ 110.6
Proceeds from issuance of common units							110.6	$ 12.9
Proceeds from issuance of Preferred Units							$ 724.1
Percentage of available cash to distribute			100.00%				100.00%
Period after quarter for distribution							45 days
General Partner | Incentive Distribution Level 1
Partners' capital
Incentive Distribution Percentage Levels							13.00%
Incentive Distribution, Distribution Per Unit | $ / shares							$ 0.25
General Partner | Incentive Distribution Level 2
Partners' capital
Incentive Distribution Percentage Levels							23.00%
Incentive Distribution, Distribution Per Unit | $ / shares							$ 0.3125
General Partner | Incentive Distribution Level 3
Partners' capital
Incentive Distribution Percentage Levels							48.00%
Incentive Distribution, Distribution Per Unit | $ / shares							$ 0.375
Common Unit
Partners' capital
Distribution declared to limited partner (in dollars per unit) | $ / shares			$ 0.39	$ 0.39	$ 0.39	$ 0.39
Common Unit | BMO EDA
Partners' capital
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
Class C Common Units
Partners' capital
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
Partners' capital
Paid in kind dividend (in units) | shares			1,106,616	1,083,589	992,445		2,100,000
Ratio of common units	1
Issuance of units in private placement (in units) | shares	50,000,000						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
Preferred Stock, Conversion Basis	150.00%
Percent Of Issue Price	140.00%
Annual Rate On Issue Price Payable In-Kind	8.50%
Annual Rate On Issue Price Payable In Cash	7.50%
Annual Rate On Issue Price	1.00%
Net Income (Loss) Allocated To Preferred			$ 19.4				$ 49.2

Partners Capital (EPU) (Details

Partners Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Millions	Aug. 11, 2016	May 12, 2016	Nov. 12, 2015	Aug. 13, 2015	May 14, 2015	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Limited partners’ interest in net income (loss)						$ (11.4)				$ (745.2)	$ (602.1)	$ (700.5)
Total distributed earnings						132.4				125.7	389.6	341
Total undistributed loss						$ (143.8)				$ (870.9)	$ (991.7)	$ (1,041.5)
Basic income (loss) (in dollars per unit)						$ (0.03)				$ (2.32)	$ (1.82)	$ (2.38)
Diluted income (loss) (in dollars per unit)						$ (0.03)				$ (2.32)	$ (1.82)	$ (2.38)
Common Unit
Limited partners’ interest in net income (loss)						$ (11.3)				$ (742.4)	$ (598.1)	$ (697.6)
Total distributed earnings						131.5				125.2	387	339.5
Total undistributed loss						$ (142.8)				(867.6)	(985.1)	(1,037.1)
Distribution declared to limited partner (in dollars per unit)						$ 0.39	$ 0.39	$ 0.39	$ 0.39
Distribution paid to limited partner (in dollars per unit)	$ 0.39	$ 0.39	$ 0.39	$ 0.385	$ 0.38
Restricted Incentive Units
Limited partners’ interest in net income (loss)						$ (0.1)				(2.8)	(4)	(2.9)
Total distributed earnings						0.9				0.5	2.6	1.5
Total undistributed loss						$ (1)				$ (3.3)	$ (6.6)	$ (4.4)

Partners Capital (Units) (Detai

Partners Capital (Units) (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Units
Weighted average limited partner basic common units outstanding (in units)	337,200,000	327,900,000	330,800,000	298,900,000
Total weighted average limited partner diluted common units outstanding (in units)	337,200,000	327,900,000	330,800,000	298,900,000
Class C Common Units
Units
Weighted average impact of conversion to common units (in units)		6,867,012	3,645,688	4,939,219
Class E Common Units
Units
Weighted average impact of conversion to common units (in units)		13,537,133		9,258,104

Partners Capital (Income Alloca

Partners Capital (Income Allocated) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Incentive
General partner interest in net income	$ 10.8	$ 6.3	$ 28.8	$ 50.2
General Partner
Incentive
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

Asset Retirement Obligation (De

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

Investment in Unconsolidated 54

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
Schedule of 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 unconsolidated affiliates	$ 266.4		$ 266.4		$ 274.3
Gulf Coast Fractionators
Schedule of Equity Method Investments
Equity method investment ownership (as a percent)	38.75%	38.75%	38.75%	38.75%
Distributions	$ 0.9	$ 3.8	$ 4.4	$ 10.7
Equity in income	2.2	3.4	1.1	9.7
Investment in unconsolidated affiliates	$ 49.2		$ 49.2		52.6
Howard Energy Partners
Schedule of Equity Method Investments
Equity method investment ownership (as a percent)	31.00%		31.00%
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 unconsolidated affiliates	217.2		217.2		$ 221.7
Preferred Units | Howard Energy Partners
Schedule of Equity Method Investments
Contributions	3.2		32.7
Distributions	$ 32.7		$ 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
Compensation 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
Allocated Share-based Compensation Expense		$ 7.3	$ 7.3	$ 22.5	$ 28.6
General and Administrative
Compensation allocation
Allocated Share-based Compensation Expense		5.7	6.3	17.5	24.6
Operating
Compensation allocation
Allocated Share-based Compensation Expense		$ 1.6	$ 1	$ 5	$ 4

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 Incentive Units
Number of Units
Non-vested, beginning of period (in units)		1,253,729			1,253,729
Granted (in units)					1,058,732
Vested (in units)					(315,686)
Forfeited (in units)					(57,601)
Non-vested, end of period (in units)			1,939,174		1,939,174
Aggregate intrinsic value, end of period (in dollars)			$ 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
Shares Paid for Tax Withholding for Share Based Compensation					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
Performance Units
Number of Units
Non-vested, beginning of period (in units)		118,126			118,126
Granted (in units)					258,078
Forfeited (in units)					(2,798)
Non-vested, end of period (in units)			373,406		373,406
Aggregate intrinsic value, end of period (in dollars)			$ 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
Grant date fair value assumptions
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%
ENLC | Restricted Incentive Units
Number of Units
Non-vested, beginning of period (in units)		1,148,893			1,148,893
Granted (in units)					1,051,410
Vested (in units)					(339,399)
Forfeited (in units)					(53,872)
Non-vested, end of period (in units)			1,807,032		1,807,032
Aggregate intrinsic value, end of period (in dollars)			$ 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
Shares Paid for Tax Withholding for Share Based Compensation					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
ENLC | Performance Units
Number of Units
Non-vested, beginning of period (in units)		105,080			105,080
Granted (in units)					242,646
Forfeited (in units)					(2,525)
Non-vested, end of period (in units)			345,201		345,201
Aggregate intrinsic value, end of period (in dollars)			$ 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
Grant date fair value assumptions
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%
Minimum | Performance Units
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					0.00%
Minimum | ENLC | Performance Units
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					0.00%
Maximum | Performance Units
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					200.00%
Maximum | ENLC | Performance Units
Weighted Average Grant-Date Fair Value
Vesting (as a percent)					200.00%

Derivatives (Income Expense) (D

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

Derivatives (Assets Liabilities

Derivatives (Assets Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivatives
Fair value of derivative assets	$ 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 (Outstanding) (Deta

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

Derivatives (Interest) (Details

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

Fair Value Measurement (Details

Fair Value Measurement (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Measured at fair value
Fair Value	$ (2.2)	$ 13.8
Commodity Swap
Measured at fair value
Fair Value	(2.2)
Level 2 | Recurring
Measured at fair value
Fair Value	(2.2)	13.8
Level 2 | Commodity Swap | Recurring
Measured at fair value
Fair Value	$ (2.2)	$ 13.8

Fair Value Measurement (FV Debt

Fair Value Measurement (FV Debt) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value
Line of credit amount outstanding	$ 75	$ 414
Senior unsecured debt	3,100	2,700
Carrying Value
Fair Value
Long-term Debt, Fair Value	3,222.8	3,066.8
Installment Payable, Fair Value	459.8
Capital Lease Obligation, Fair Value	10.5	16.7
Fair Value
Fair Value
Long-term Debt, Fair Value	3,101.4	2,585.5
Installment Payable, Fair Value	464.5
Capital Lease Obligation, Fair Value	$ 9.7	$ 15.6
Minimum
Fair Value
Fixed interest rate (as a percent)	2.70%
Maximum
Fair Value
Fixed interest rate (as a percent)	7.10%

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	Jul. 29, 2016	Aug. 31, 2014
Commitments and Contingencies.
Environmental fine offered	$ 0.1
Gain on litigation settlement		$ 6.1

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 31, 2014	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 on litigation settlement	$ 6.1
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)	(566.3)	(799.2)
Goodwill		422.3	1,729.9	422.3	1,729.9	$ 987
Capital expenditures		146.9	104.7	407.5	445.2
Identifiable assets		9,075.9		9,075.9		8,092.8
Corporate
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)
Capital expenditures		8.6	3.9	15.4	10.6
Identifiable assets		350.6		350.6		302.6
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
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
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
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
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 profit	$ 218.4	$ 203.8	$ 624.4	$ 585.6
General and administrative expenses	(28.3)	(33.5)	(90.6)	(102.3)
Gain (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)	(566.3)	(799.2)
Operating income (loss)	$ 66.9	$ (730.5)	$ (402.6)	$ (608.2)

Supplemental Cash Flow Inform66

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	Jan. 07, 2016	Sep. 30, 2016	Sep. 30, 2015
Noncash Transactions
Non-cash adjustment of interest in Midstream Holdings			$ 66.5
Tall Oak
Noncash Transactions
Installment payable, net of discount of $79.1 million	$ 420.9	$ 420.9
Installment payable discount	$ 79.1	79.1	79.1
Contribution from ENLC		237.1
Installment payment		$ 250
Coronado | Common Unit
Noncash Transactions
Non-cash issuance of units			180
Coronado | Class C Common Units
Noncash Transactions
Non-cash issuance of units			$ 180

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Other Information
Accrued interest	$ 58	$ 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	57.2
Other current liabilities	$ 196.2	$ 174.4