ENLK-2015.6.30-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

for the quarterly period ended June 30, 2015

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

for the transition period from to

Commission file number: 001-36340

ENLINK MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware		16-1616605
(State of organization)		(I.R.S. Employer Identification No.)

2501 CEDAR SPRINGS RD.
DALLAS, TEXAS		75201
(Address of principal executive offices)		(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer x		Accelerated filer o

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

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

As of July 24, 2015, the Registrant had 284,429,533 common units, 6,804,079 Class C Common Units and 36,629,888 Class E Common Units outstanding.

TABLE OF CONTENTS



Item	Description	Page

	PART I—FINANCIAL INFORMATION

1.	Financial Statements	3

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37

3.	Quantitative and Qualitative Disclosures About Market Risk	54

4.	Controls and Procedures	56

	PART II—OTHER INFORMATION

1.	Legal Proceedings	56

1A.	Risk Factors	56

6.	Exhibits	58

ENLINK MIDSTREAM PARTNERS, LP

Condensed Consolidated Balance Sheets



	June 30, 2015		December 31, 2014
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	8.1	$	9.6
Accounts receivable:
Trade, net of allowance for bad debt of $0.4	67.4		139.0
Accrued revenue and other	379.6		253.3
Related party	110.9		121.6
Fair value of derivative assets	14.0		16.7
Natural gas and NGLs inventory, prepaid expenses and other	53.3		30.8
Total current assets	633.3		571.0
Property and equipment, net of accumulated depreciation of $1,585.7 and $1,426.3, respectively	5,550.5		5,042.8
Intangible assets, net of accumulated amortization of $66.3 and $36.5, respectively	840.5		533.0
Goodwill	2,304.2		2,257.8
Fair value of derivative assets	4.9		10.0
Investments in unconsolidated affiliates	261.2		270.8
Other assets, net	24.7		16.6
Total assets	$	9,619.3	$	8,702.0

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	39.1	$	121.8
Accounts payable to related party	21.6		3.0
Accrued gas, NGLs, condensate and crude oil purchases	316.3		204.5
Fair value of derivative liabilities	3.5		3.0
Other current liabilities	164.3		149.8
Total current liabilities	544.8		482.1
Long-term debt	2,827.2		2,022.5
Fair value of derivative liabilities	0.8		2.0
Asset retirement obligation	12.6		12.4
Other long-term liabilities	75.2		84.0
Deferred tax liability	77.2		73.1

Redeemable non-controlling interest	6.9		—

Partners’ equity:
Common unitholders (321,058,288 units issued and outstanding at June 30, 2015 and 245,421,549 units issued and outstanding at December 31, 2014)	5,666.8		5,833.3
Class C unitholders (6,804,079 units issued and outstanding at June 30, 2015)	180.8		—
General partner interest (1,594,974 equivalent units outstanding at June 30, 2015 and December 31, 2014)	219.8		180.3
Non controlling interest	7.2		12.3
Total partners' equity	6,074.6		6,025.9
Commitment and Contingencies (Note 13)
Total liabilities and partners’ equity	$	9,619.3	$	8,702.0

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Condensed Consolidated Statements of Operations



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited) (In millions, except per unit amounts)
Revenues:
Product sales	$	956.2		$	687.9		$	1,626.9		$	901.3
Product sales - affiliates	31.7			—			47.9			436.4
Midstream services	135.9			67.1			238.3			86.2
Midstream services - affiliates	149.5			173.8			300.5			229.3
Gain (loss) on derivative activity	1.2			(1.6		)	1.4			(2.9		)
Total revenues	1,274.5			927.2			2,215.0			1,650.3
Operating costs and expenses:
Cost of sales (1)	968.2			661.9			1,625.6			1,200.8
Operating expenses (2)	109.1			73.9			207.6			120.6
General and administrative (3)	27.0			25.8			68.8			41.3
Depreciation and amortization	97.7			74.5			189.0			123.0
Total operating costs and expenses	1,202.0			836.1			2,091.0			1,485.7
Operating income	72.5			91.1			124.0			164.6
Other income (expense):
Interest expense, net of interest income	(22.4		)	(13.2		)	(41.3		)	(18.0		)
Equity in income of equity investment	5.9			4.5			9.7			8.7
Gain on extinguishment of debt	—			0.8			—			0.8
Other income (expense)	0.1			(0.1		)	0.6			(0.8		)
Total other expense	(16.4		)	(8.0		)	(31.0		)	(9.3		)
Income from continuing operations before non-controlling interest and income taxes	56.1			83.1			93.0			155.3
Income tax provision	(0.7		)	(1.2		)	(1.9		)	(20.8		)
Net income from continuing operations	55.4			81.9			91.1			134.5
Discontinued operations:
Income from discontinued operations, net of tax	—			—			—			1.0
Discontinued operations, net of tax	—			—			—			1.0
Net income	55.4			81.9			91.1			135.5
Net income (loss) attributable to the non-controlling interest	(0.1		)	0.1			—			0.1
Net income attributable to EnLink Midstream Partners, LP	$	55.5		$	81.8		$	91.1		$	135.4
Predecessor interest in net income (4)	$	—		$	—		$	—		$	35.5
General partner interest in net income	$	19.1		$	43.5		$	45.6		$	53.9
Limited partners’ interest in net income attributable to EnLink Midstream Partners, LP	$	35.7		$	38.3		$	44.7		$	46.0
Class C partners’ interest in net income attributable to EnLink Midstream Partners, LP	$	0.7		$	—		$	0.8		$	—
Net income attributable to EnLink Midstream Partners, LP per limited partners’ unit:
Basic per common unit	$	0.12		$	0.17		$	0.16		$	0.20
Diluted per common unit	$	0.12		$	0.17		$	0.16		$	0.20

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

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

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

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

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity

Six Months Ended June 30, 2015



	Common Units				Class C Common Units			General Partner Interest				Non-Controlling Interest						Redeemable Non-controlling Interest (Temporary Equity)
	$			Units	$		Units	$			Units	$			Total			$
	(Unaudited)
	(In millions)
Balance, December 31, 2014	$	5,833.3		245.4	$	—	—	$	180.3		1.6	$	12.3		$	6,025.9		$	—
Issuance of common units	184.1			75.5	180.0		6.7	—			—	—			364.1			—
Conversion of restricted units for common units, net of units withheld for taxes	(2.5		)	0.2	—		—	—			—	—			(2.5		)	—
Unit-based compensation	10.5			—	—		—	10.9			—	—			21.4			—
Contribution from Devon	28.8			—	—		—	—			—	—			28.8			—
Distribution attributable to net assets transferred (Note 3)	(171.0		)	—	—		—	—			—	—			(171.0		)
Distributions	(194.6		)	—	—		0.1	(17.0		)	—	—			(211.6		)	—
Non-controlling interest contributions	—			—	—		—	—			—	7.2			7.2			—
Distributions to non-controlling interest	—			—	—		—	—			—	(66.5		)	(66.5		)	—
Adjustment related to mandatory redemption of E2 non-controlling interest	—			—	—		—	—			—	(5.4		)	(5.4		)	—
Redeemable non-controlling interest	—			—	—		—	—			—	(6.9		)	(6.9		)	6.9
Transfer of interest in Midstream Holdings (Note 3)	(66.5		)	—	—		—	—			—	66.5			—			—
Net income	44.7			—	0.8		—	45.6			—	—			91.1			—
Balance, June 30, 2015	$	5,666.8		321.1	$	180.8	6.8	$	219.8		1.6	$	7.2		$	6,074.6		$	6.9

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Consolidated Statements of Cash Flows



	Six Months Ended June 30,
	2015			2014
	(Unaudited) (In millions)
Cash flows from operating activities:
Net income from continuing operations	$	91.1		$	134.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	189.0			123.0
Accretion expense	0.3			0.3
Gain on extinguishment of debt	—			(0.8		)
Deferred tax expense	—			20.0
Non-cash unit-based compensation	21.4			6.9
(Gain) loss on derivatives recognized in net income	(5.0		)	2.9
Cash settlements on derivatives	11.3			(0.9		)
Amortization of debt issue costs	1.4			0.4
Amortization of premium on notes	(1.5		)	(1.0		)
Redeemable non-controlling interest expense	(3.3		)	—
Distribution of earnings from equity investment	10.3			0.7
Equity in income from equity investments	(9.7		)	(8.7		)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	57.3			5.0
Natural gas and NGLs inventory, prepaid expenses and other	(18.3		)	(15.1		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(52.0		)	(45.8		)
Net cash provided by operating activities	292.3			221.4
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment	(349.2		)	(336.7		)
Acquisition of business, net of cash acquired	(324.8		)	(93.9		)
Proceeds from sale of property	0.1			—
Investment in limited liability company	—			(5.7		)
Distribution from equity investment company in excess of earnings	8.9			5.0
Net cash used in investing activities	(665.0		)	(431.3		)
Cash flows from financing activities:
Proceeds from borrowings	2,327.4			1,613.7
Payments on borrowings	(1,521.2		)	(1,391.5		)
Payments on capital lease obligations	(1.6		)	(1.2		)
Increase (decrease) in drafts payable	(12.4		)	8.6
Debt financing costs	(9.5		)	(6.2		)
Conversion of restricted units, net of units withheld for taxes	(2.5		)	—
Proceeds from issuance of common units	4.1			19.9
Proceeds from exercise of unit options	—			0.3
Distributions to non-controlling partners	(66.5		)	(51.8		)
Contributions by non-controlling partners	7.2			1.2
Distributions to partners	(211.6		)	(55.6		)
Contributions from Devon	28.8			95.3
Distributions to Devon for net assets acquired (Note 3)	(171.0		)	—
Distributions to Predecessor	—			(22.1		)
Net cash provided by financing activities	371.2			210.6
Cash flow from discontinued operations:
Net cash provided by operating activities	—			5.0
Net cash used in investing activities	—			(0.6		)
Net cash used in financing activities – net distributions to Devon and non-controlling interests	—			(4.4		)
Net cash provided by discontinued operations	—			—
Net increase (decrease) in cash and cash equivalents	(1.5		)	0.7
Cash and cash equivalents, beginning of period	9.6			0.1
Cash and cash equivalents, end of period	$	8.1		$	0.8
Cash paid for interest	$	44.0		$	17.3
Cash paid for income taxes	$	0.1		$	6.9

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements

June 30, 2015

(Unaudited)

(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 Midstream Holdings (as defined below) and their consolidated subsidiaries. The term “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization of Business

EnLink Midstream 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 (the “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 70% of the outstanding limited liability company interests in ENLC.

Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by the Partnership of 120,542,441 units representing limited partnership interests in the Partnership. At the same time, EnLink Midstream, Inc. (“EMI”), the entity that directly owns our General Partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “business combination”). At the conclusion of the business combination, another wholly-owned subsidiary of ENLC, Acacia Natural Gas Corp. I, Inc. (“Acacia”), owned the remaining 50% of the outstanding equity interests in Midstream Holdings.

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

(b)Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. 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 our south Louisiana processing plants to our fractionators in south Louisiana. 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 arrangements. Our processing plants remove NGLs and CO₂ 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. We also provide a variety of crude oil and

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

condensate services which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucking facilities as well as brine disposal services.

(2) Significant Accounting Policies

(a) Basis of Presentation

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

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner as a result of the business combination. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, the Partnership’s assets acquired and liabilities assumed by Midstream Holdings in the business combination were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of the Partnership’s net assets acquired was recorded as goodwill. Financial results subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and the Partnership, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non contributed assets have been presented as discontinued operations. In conjunction with the business combination, Midstream Holdings became a non-taxable entity which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from ENLC and Devon through drop down transactions. Due to ENLC's control of the Partnership through its ownership and control of the General Partner and Devon's control of the Partnership 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, the Partnership was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from 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 the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to the Partnership’s acquisition is allocated to the general partner.

(b) Revenue Recognition

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


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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)


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

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

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

(d) Recent Accounting Pronouncements

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

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

In April 2015, the FASB issued ASU No. 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force), 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. The ASU 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 fiscal years. The ASU requires retrospective application and early adoption is permitted.

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(3) Acquisitions

Chevron Acquisition

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

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



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

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

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

LPC Acquisition

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



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

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

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

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

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

Coronado Acquisition

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

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



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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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

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

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

EMH Drop Downs

On February 17, 2015, the Partnership acquired an additional 25% limited partner interest in Midstream Holdings from Acacia in the February EMH Drop Down. As consideration for the February Transferred Interests, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they received only a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, the Partnership acquired the remaining 25% limited partner interest in Midstream Holdings from Acacia in the May EMH Drop Down in exchange for 36.6 million Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units are substantially similar in all respects to the Partnership’s common units, except that they are only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015, which was the first business day following the record date for distribution payments with respect to the distribution for the quarter ended June 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. The period of common control for EMH began on March 7, 2014, the effective date of the business combination described under "Devon Transaction" below.

The Partnership accounted for the acquisition of the EMH Drop Downs from Acacia as a transfer between entities under common control in accordance with ASC 805-50-30. As such, the February Transferred Interests and May Transferred Interests were recorded on the Partnership’s books at historical cost on the date of transfer, which was February 17, 2015 and May 27, 2015, respectively. The “Transfer of interest in Midstream Holdings” presented in the Consolidated Statement of Changes in Partners’ Equity represents the adjustment to equity due to the recast to offset distributions paid to ENLC for its related ownership during the period January 1, 2015 to May 27, 2015.

VEX Pipeline Drop Down

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

E2 Drop Down

On October 22, 2014, the Partnership acquired all remaining voting equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) in a drop down transaction from EMI (the "E2 Drop Down"). The total

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

consideration for the transaction was approximately $194.0 million, including a cash payment of $163.0 million and the issuance of approximately 1.0 million Partnership units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the Partnership's units). This acquisition has been accounted for as an acquisition under common control under ASC 805. The period of common control for E2 began on March 7, 2014, the effective date of the business combination described in "Devon Transaction" below.

The following tables present the collective impact of the E2 Drop Down, the VEX Drop Down and the EMH Drop Downs as presented in the Partnership's historical Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and the six months ended June 30, 2015:



	Six Months Ended June 30, 2015
	Partnership Historical		EMH			VEX		Combined
	(in millions)
Revenues	$	2,210.8	$	—		$	4.2	$	2,215.0
Net income (loss)	$	90.4	$	—		$	0.7	$	91.1
Net income attributable to non-controlling interest	$	15.3	$	(15.3	)	$	—	$	—
Net income attributable to EnLink Midstream Partners, LP	$	75.1	$	15.3		$	0.7	$	91.1
General partner interest in net income	$	29.6	$	15.3		$	0.7	$	45.6



	Three Months Ended June 30, 2014
	Partnership Historical		EMH			E2			VEX			Combined
	(in millions)
Revenues	$	924.0	$	—		$	3.2		$	—		$	927.2
Net income (loss)	$	84.1	$	—		$	(0.1	)	$	(2.1	)	$	81.9
Net income attributable to non-controlling interest	$	42.7	$	(42.7	)	$	0.1		$	—		$	0.1
Net income attributable to EnLink Midstream Partners, LP	$	41.4	$	42.7		$	(0.2	)	$	(2.1	)	$	81.8
General partner interest in net income	$	3.1	$	42.7		$	(0.2	)	$	(2.1	)	$	43.5



	Six Months Ended June 30, 2014
	Partnership Historical		EMH**			E2			VEX**			Combined
	(in millions)
Revenues	$	1,646.5	$	—		$	3.8		$	—		$	1,650.3
Net income (loss)	$	138.6	$	—		$	(0.1	)	$	(3.0	)	$	135.5
Net income attributable to non-controlling interest	$	53.1	$	(53.1	)	$	0.1		$	—		$	0.1
Net income attributable to EnLink Midstream Partners, LP	$	85.5	$	53.1		$	(0.2	)	$	(3.0	)	$	135.4
General partner interest in net income	$	4.0	$	53.1		$	(0.2	)	$	(3.0	)	$	53.9

* * Represents the VEX Interests and Transferred Interests amounts for the period from March 7, 2014 through June 30, 2014.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Devon Transaction

As discussed in Note 1(a), on March 7, 2014, the Partnership acquired, through one of its wholly owned subsidiaries, 50% of the outstanding equity interests in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by the Partnership of 120.5 million units representing a new class of limited partnership interests in the Partnership (the “Class B Units”). Midstream Holdings owns midstream assets in the Barnett Shale in North Texas and the Cana-Woodford and Arkoma-Woodford Shales in Oklahoma, as well as a contractual right to the economic burdens and benefits of Devon’s 38.75% interest in Gulf Coast Fractionators (“GCF”) in Mt. Belvieu, Texas.

Under the acquisition method of accounting, Midstream Holdings was the acquirer in the business combination because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values and the Partnership’s assets acquired and liabilities assumed by Midstream Holdings as the Predecessor in the business combination have been recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of the Partnership’s net assets acquired has been recorded as goodwill.

For the period from March 7, 2014 to June 30, 2014, the Partnership recognized $968.8 million of revenues and $3.2 million of net loss related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, EMH Drop Downs, VEX Drop Down and E2 Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Pro forma financial information associated with the business combination and acquisitions is reflected below.



		Three Months Ended June 30,		Six Months Ended June 30,
		2014		2015		2014
	(in millions)
Pro forma total revenues (1)		$	1,453.4	$	2,337.1	$	2,833.2
Pro forma net income		$	71.8	$	85.9	$	105.6
Pro forma net income attributable to EnLink Midstream Partners, LP		$	71.7	$	85.9	$	105.5
Pro forma net income per common unit:
Basic		$	0.11	$	0.14	$	0.11
Diluted		$	0.11	$	0.14	$	0.11

(1)On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which

are described in Note 5.

(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

comparing the implied fair value to the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. The Partnership performed its annual impairment test of goodwill as of the fourth quarter of 2014. Based on these assessments, no impairment of goodwill was required.

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



	June 30, 2015		December 31, 2014
	(in millions)
Texas	$	1,185.0	$	1,168.2
Louisiana	786.8		786.8
Oklahoma	190.3		190.3
Crude and Condensate	142.1		112.5
Total	$	2,304.2	$	2,257.8

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

Intangible Assets

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

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



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

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

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



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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(5) Affiliate Transactions

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

Gathering, Processing and Transportation Agreements with Devon

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

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

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

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

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

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. The terms of these agreements vary,

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

but the agreements expire between July 2015 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee. These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

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

Transition Services Agreement

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

Drop Down Transactions

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from ENLC and Devon through drop down transactions. See Note (3) - Acquisitions for further discussion.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Predecessor Affiliate Transactions

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

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



	Six Months Ended June 30, 2014
Continuing Operations:
Revenues - affiliates	$	(436.4	)
Operating cost and expenses - affiliates	340.0
Net affiliate transactions	(96.4		)
Capital expenditures	21.3
Other third-party transactions, net	53.0
Net third-party transactions	74.3
Net cash distributions to Devon - continuing operations	(22.1		)
Non-cash distribution of net assets to Devon	(23.2		)
Total net distributions per equity	$	(45.3	)

Discontinued operations:
Revenues - affiliates	$	(10.4	)
Operating costs and expenses - affiliates	5.0
Net affiliate transactions	(5.4		)
Capital expenditures	0.6
Other third-party transactions, net	0.4
Net third-party transactions	1.0
Net cash distributions to Devon and non-controlling interests - discontinued operations	(4.4		)
Non-cash distribution of net assets to Devon	(39.9		)
Total net distributions per equity	$	(44.3	)
Total distributions- continuing and discontinued operations	$	(89.6	)

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(6) Long-Term Debt

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



	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9%, respectively	$	150.0	$	237.0
Senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
Senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
Senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
Senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%	349.7		349.7
Senior unsecured notes (due 2045), net of discount of $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

Credit Facility

On February 20, 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion, and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership credit facility by an additional amount not to exceed $500 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA may be increased to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the Partnership credit facility bear interest at the Partnership’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin. The applicable margins vary depending on the Partnership’s credit rating. Upon breach by the Partnership of certain covenants governing the Partnership credit facility, amounts outstanding under the Partnership credit facility, if any, may become due and payable immediately.

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

All other material terms of the Partnership credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014, as recast by the Partnership's Current Report on Form 8-K dated May 28, 2015. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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

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

Prior to October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2045 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2045 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to 100% of the principal amount of the 2045 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of our assets.

Each of the following is an event of default under the indentures:


•	failure to pay any principal or interest when due;


•	failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures;


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


•	failure by us to pay final judgments that exceed a certain threshold amount; and


•	bankruptcy or other insolvency events involving us.

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies.

(7) Partners’ Capital

(a) Issuance of Common Units

In November 2014, the Partnership entered into an Equity Distribution Agreement (the “BMO EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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

(b) Class C Common Units

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

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

(d) Class E Common Units

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

(e) Distributions

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

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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



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

(1)

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


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

(3)

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

(f) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders. The following table reflects the computation of basic and diluted earnings per limited partner unit for the period presented (in millions, except per unit amounts):



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014*
Limited partners’ interest in net income	$	35.7		$	38.3		$	44.7		$	46.0
Distributed earnings allocated to:
Common units (1) (2) (3)	$	117.6		$	83.8		$	214.4		$	135.2
Unvested restricted units (1)	0.4			0.4			0.9			0.6
Total distributed earnings	$	118.0		$	84.2		$	215.3		$	135.8
Undistributed loss allocated to:
Common units (2) (3)	$	(82.0	)	$	(45.7	)	$	(169.9	)	$	(89.5	)
Unvested restricted units	(0.3		)	(0.2		)	(0.7		)	(0.3		)
Total undistributed loss	$	(82.3	)	$	(45.9	)	$	(170.6	)	$	(89.8	)
Net income allocated to:										0
Common units (2) (3)	$	35.6		$	38.1		$	44.5		$	45.7
Unvested restricted units	0.1			0.2			0.2			0.3
Total limited partners’ interest in net income	$	35.7		$	38.3		$	44.7		$	46.0
Basic and diluted net income per unit:
Basic	$	0.12		$	0.17		$	0.16		$	0.20
Diluted	$	0.12		$	0.17		$	0.16		$	0.20

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


(1)	Three months ended June 30, 2015 and 2014 represents a declared distribution of $0.385 per unit payable on August 13, 2015 and declared distribution of $0.365 per unit for common units paid on August 13, 2014, respectively.


(2)	Six months ended June 30, 2015 and 2014 represents distributions paid of $0.38 per unit on May 14, 2015 and a declared distribution of $0.385 per unit payable on August 13, 2015 and distributions paid of $0.36 per unit on May 14, 2014 and of $0.365 per unit on August 13, 2014.


(3)	Six months ended June 30, 2015 includes declared partial distribution of $0.15 per unit for Class E Common Units payable on August 13, 2015 and declared partial distribution of $0.18 per unit for Class D Common Units paid on May 14, 2015. The three and six months ended June 30, 2014 includes a declared partial distribution of $0.10 per unit for Class B Common Units paid on May 14, 2014.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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 June 30,		Six Months Ended June 30,
Basic weighted average units outstanding:	2015	2014	2015	2014*
Weighted average limited partner basic common units outstanding	284.3	229.8	273.1	229.7
Weighted average Class C Common Units outstanding	6.8	—	4.0	—
Weighted average Class E Common Units outstanding	14.1	—	7.1	—
Total weighted average limited partner common units outstanding	305.2	229.8	284.2	229.7
Diluted weighted average units outstanding:
Weighted average limited partner basic common units outstanding	305.2	229.8	284.2	229.7
Dilutive effect of restricted units issued	0.4	0.3	0.4	0.3
Total weighted average limited partner diluted common units outstanding	305.6	230.1	284.6	230.0

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

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

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 7(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the periods presented (in millions).



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

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

(8) Asset Retirement Obligations

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



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

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(9) Investment in Unconsolidated Affiliates

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

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



	Gulf Coast Fractionators		Howard Energy Partners		Total
Three months ended
June 30, 2015
Distributions	$	4.2	$	8.2	$	12.4
Equity in income	$	2.9	$	3.0	$	5.9

June 30, 2014 (1)
Distributions	$	—	$	3.0	$	3.0
Equity in income	$	3.9	$	0.6	$	4.5

Six months ended
June 30, 2015
Distributions	$	6.9	$	12.3	$	19.2
Equity in income	$	6.3	$	3.4	$	9.7

June 30, 2014 (1)
Distributions	$	—	$	5.7	$	5.7
Equity in income	$	8.0	$	0.7	$	8.7

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

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



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

(10) Employee Incentive Plans

(a) Long-Term Incentive Plans

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Cost of unit-based compensation allocated to Predecessor general and administrative expense (1)	$	—	$	—	$	—	$	2.8
Cost of unit-based compensation charged to general and administrative expense	6.5		4.9		18.4		5.9
Cost of unit-based compensation charged to operating expense	1.1		0.8		3.0		1.0
Total amount charged to income	$	7.6	$	5.7	$	21.4	$	9.7


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

(b) EnLink Midstream Partners, LP Restricted Incentive Units

The Partnership's restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2015 is provided below:



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

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

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



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

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

In March 2015, the Partnership and ENLC granted performance awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the "GP Plan") and the 2014 Long-Term Incentive Plan (the “LLC Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding the Partnership and 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 with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership and the designated peer group; (iii) an estimated ranking of the Partnership among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions.



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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



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

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

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

ENLC’s restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of the common units on such date. A summary of the restricted incentive units activity for the six months ended June 30, 2015 is provided below:



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

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

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



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

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(e) EnLink Midstream, LLC's Performance Units

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



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

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



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

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

(11) Derivatives

Interest Rate Swaps

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

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



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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

Commodity Swaps

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

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

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



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

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

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



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

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



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

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements ("ISDAs") that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss as of June 30, 2015 of $18.9 million would be reduced to $14.6 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

Fair Value of Derivative Instruments

Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as a loss on derivatives in the Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):



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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(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, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

FASB ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

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



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

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

Fair Value of Financial Instruments

The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):



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

The carrying amounts of the Partnership’s cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

The Partnership had $150.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of June 30, 2015 and December 31, 2014, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2015, the Partnership had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. As of December 31, 2014, the Partnership had total borrowings of $1.8 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

value of all senior unsecured notes as of June 30, 2015 and December 31, 2014 was based on Level 2 inputs from third-party market quotations. The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

(13) Commitments and Contingencies

(a) Severance and Change in Control Agreements

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

(b) Environmental Issues

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's results of operations, financial condition or cash flows.

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

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

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

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. The Partnership's subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable.

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

In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its fractionation plants. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

(14) Segment Information

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

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

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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)



	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
	(In millions)
Three Months Ended June 30, 2015
Product sales	$	81.2		$	401.2		$	0.1		$	473.7		$	—		$	956.2
Product sales-affiliates	35.0			17.0			1.7			14.0			(36.0		)	31.7
Midstream services	36.0			63.2			9.8			26.9			—			135.9
Midstream services-affiliates	115.8			0.3			29.1			4.3			—			149.5
Cost of sales	(118.4		)	(418.2		)	(2.0		)	(465.6		)	36.0			(968.2		)
Operating expenses	(45.5		)	(27.2		)	(9.1		)	(27.3		)	—			(109.1		)
Gain on derivative activity	—			—			—			—			1.2			1.2
Segment profit	$	104.1		$	36.3		$	29.6		$	26.0		$	1.2		$	197.2
Depreciation and amortization	$	(42.8	)	$	(26.9	)	$	(11.8	)	$	(14.5	)	$	(1.7	)	$	(97.7	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	—		$	2,304.2
Capital expenditures	$	80.9		$	14.7		$	12.3		$	54.4		$	2.5		$	164.8
Three Months Ended June 30, 2014
Product sales	$	68.6		$	514.2		$	—		$	105.1		$	—		$	687.9
Product sales-affiliates	19.3			1.7			—			—			(21.0		)	—
Midstream services	14.6			37.9			—			14.6			—			67.1
Midstream services-affiliates	126.6			—			47.2			—			—			173.8
Cost of sales	(76.1		)	(508.1		)	—			(98.7		)	21.0			(661.9		)
Operating expenses	(38.6		)	(16.5		)	(7.3		)	(11.5		)	—			(73.9		)
Loss on derivative activity	—			—			—			—			(1.6		)	(1.6		)
Segment profit	$	114.4		$	29.2		$	39.9		$	9.5		$	(1.6	)	$	191.4
Depreciation and amortization	$	(32.8	)	$	(19.1	)	$	(11.6	)	$	(10.5	)	$	(0.5	)	$	(74.5	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	112.5		$	—		$	2,257.6
Capital expenditures	$	75.4		$	121.2		$	(2.2	)	$	33.9		$	3.2		$	231.5

Six Months Ended June 30, 2015
Product sales	$	131.0		$	773.4		$	0.1		$	722.4		$	—		$	1,626.9
Product sales-affiliates	60.9			24.1			5.4			14.0			(56.5		)	47.9
Midstream services	55.6			121.1			20.5			41.1			—			238.3
Midstream services-affiliates	231.3			0.4			60.3			8.5			—			300.5
Cost of sales	(185.6		)	(789.1		)	(7.1		)	(700.3		)	56.5			(1,625.6		)
Operating expenses	(92.6		)	(51.5		)	(16.1		)	(47.4		)	—			(207.6		)
Gain on derivative activity	—			—			—			—			1.4			1.4
Segment profit	$	200.6		$	78.4		$	63.1		$	38.3		$	1.4		$	381.8
Depreciation and amortization	$	(79.2	)	$	(54.4	)	$	(25.3	)	$	(26.9	)	$	(3.2	)	$	(189.0	)
Goodwill	$	1,185.0		$	786.8		$	190.3		$	142.1		$	—		$	2,304.2
Capital expenditures	$	154.4		$	29.9		$	17.5		$	132.0		$	6.7		$	340.5
Six Months Ended June 30, 2014
Product sales	$	114.5		$	649.1		$	11.5		$	126.2		$	—		$	901.3
Product sales-affiliates	311.9			2.3			147.9			—			(25.7		)	436.4
Midstream services	19.5			48.4			—			18.3			—			86.2
Midstream services-affiliates	167.0			—			62.3			—			—			229.3
Cost of sales	(333.4		)	(641.6		)	(133.9		)	(117.6		)	25.7			(1,200.8		)
Operating expenses	(70.3		)	(21.6		)	(14.0		)	(14.7		)	—			(120.6		)

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)



Loss on derivative activity	—			—			—			—			(2.9		)	(2.9		)
Segment profit	$	209.2		$	36.6		$	73.8		$	12.2		$	(2.9	)	$	328.9
Depreciation and amortization	$	(60.1	)	$	(24.3	)	$	(25.8	)	$	(12.2	)	$	(0.6	)	$	(123.0	)
Goodwill	$	1,168.1		$	786.7		$	190.3		$	112.5		$	—		$	2,257.6
Capital expenditures	$	100.5		$	143.3		$	8.0		$	45.0		$	8.7		$	305.5

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



	June 30, 2015		December 31, 2014
Segment Identifiable Assets:	(In millions)
Texas	$	4,011.7	$	3,302.9
Louisiana	3,195.5		3,316.5
Oklahoma	885.5		892.8
Crude and Condensate	1,210.6		871.8
Corporate	316.0		318.0
Total identifiable assets	$	9,619.3	$	8,702.0

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Segment profits	$	197.2		$	191.4		$	381.8		$	328.9
General and administrative expenses	(27.0		)	(25.8		)	(68.8		)	(41.3		)
Depreciation and amortization	(97.7		)	(74.5		)	(189.0		)	(123.0		)
Operating income	$	72.5		$	91.1		$	124.0		$	164.6

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(Unaudited)

(15) Discontinued Operations

The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the economic benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

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



	Six Months Ended June 30,
	2014
Revenues:
Revenues	$	6.8
Revenues - affiliates	10.5
Total revenues	17.3

Operating costs and expenses:
Operating expenses	15.7
Total operating costs and expenses	15.7

Income before income taxes	1.6
Income tax provision	0.6
Net income	$	1.0

(16) Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2015
	(In millions)
Non-cash financing activities:
Non-cash issuance of common units (1)	$	180.0
Non-cash issuance of Class C Common Units (1)	$	180.0
Non-cash adjustment of interest in Midstream Holdings (2)	$	66.5

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

(2) Non-cash adjustment to reflect recast of Midstream Holdings' interests acquired on February 17, 2015 and May 27, 2015. See Note 3 - Acquisitions for further discussion.

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

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

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

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

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

Overview

We are a Delaware limited partnership formed on July 12, 2002. We primarily focus on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, brine services and marketing to producers of natural gas, NGLs, crude oil and condensate. Our midstream energy asset network includes approximately 9,200 miles of pipelines, sixteen natural gas processing plants, seven fractionators, 3.1 million barrels of NGL cavern storage, 11.0 Bcf of natural gas storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 140 trucks. We manage and report our activities primarily according to the nature of activity and geography. We have five reportable segments: (1) Texas, which includes our natural gas gathering, processing and transmission activities in north Texas and the Permian Basin in west Texas; (2) Oklahoma, which includes our natural gas gathering, processing and transmission activities in Cana-Woodford and Arkoma-Woodford Shale areas; (3) Louisiana, which includes our natural gas pipelines, natural gas processing plants and NGL assets located in Louisiana; (4) Crude and Condensate, which includes our Ohio River Valley ("ORV") crude oil, condensate and brine disposal activities in the Utica and Marcellus Shales, our equity interests in E2 Energy Services, LLC, E2 Appalachian Compression, LLC and E2 Ohio Compression, LLC (collectively, “E2”), our crude oil operations in the Permian Basin and our crude oil activities associated with the Victoria Express Pipeline and related truck terminal and storage assets ("VEX") located in the Eagle Ford Shale; and (5) Corporate, which includes our equity investments in Howard Energy Partners in the Eagle Ford Shale, our contractual right to the economic burdens and benefits associated with Devon's ownership interest in GCF in south Texas, and our general partnership property and expenses.

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

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

•transporting natural gas and NGLs on the pipeline systems we own;

•processing natural gas at our processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services; and

•providing brine disposal services.

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

On occasion we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as our fee. Changes in the basis spread can increase or decrease our margins or potentially result in losses. For example, we are a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices on our North Texas Pipeline and sell the gas into a different market area index. We realize a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of June 30, 2015, the balance sheet reflects a liability of $71.7 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the cash losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

We typically transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. We also buy mixed NGLs from our suppliers at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. The fees we earn on the product upgrade from this fractionation business are higher during periods with higher liquids prices.

We generally gather or transport crude oil and condensate owned by others by rail, truck, pipeline and barge facilities for a fee. We also buy crude oil and condensate from a producer at a fixed discount to a market index, then transport and resell the crude oil and condensate at the same market index. We execute substantially all purchases and sales concurrently, thereby establishing the fee we will receive for each crude oil and condensate transaction. Additionally, we provide crude oil, condensate and brine services on a volume basis.

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

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

Our general and administrative expenses are dictated by the terms of our partnership agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, fees, services and other transaction costs related to acquisitions, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Devon Energy Transaction

On March 7, 2014, the Partnership consummated the transactions contemplated by the Contribution Agreement, dated as of October 21, 2013 (the “Contribution Agreement”), among the Partnership, the Operating Partnership, Devon, Devon Gas Corporation, Devon Gas Services, L.P. (“Gas Services”) and Southwestern Gas Pipeline, Inc. (“Southwestern Gas” and, together with Gas Services, the “Contributors”) pursuant to which the Contributors contributed (the “Contribution”) to the Operating Partnership a 50% limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (“Midstream Holdings GP” and, together with Midstream Holdings and their subsidiaries, the “Midstream Group Entities”), in exchange for the issuance by the Partnership of 120,542,441 units representing limited partnership interests in the Partnership.

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

On February 17, 2015, the Partnership acquired a 25% limited partner interest in Midstream Holdings (the “February Transferred Interests”) from Acacia in a drop down transaction (the “February EMH Drop Down”). As consideration for the February Transferred Interests, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia. On May 27, 2015, the Partnership acquired the remaining 25% interest in Midstream Holdings (the "May Transferred Interests" and, together with the February Transferred Interests, the "Transferred Interests") from Acacia in a drop down transaction (the "May EMH Drop Down" and, together with the February EMH Drop Down, the "EMH Drop Downs"). As consideration for the May Transferred Interests, the Partnership issued 36.6 million Class E Common Units in the Partnership to Acacia. After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings. See “Recent Developments.”

Recent Developments

Acquisitions

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

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

Drop Downs

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

EMH Drop Downs. On February 17, 2015, the Partnership acquired the February Transferred Interests from Acacia, a wholly-owned subsidiary of ENLC, in the February EMH Drop Down. As consideration for the February Transferred Interests, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, the Partnership acquired the May Transferred Interests from Acacia in exchange for 36.6 million Class E Common Units in the Partnership. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

Organic Growth

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

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

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

Credit Facility

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

Issuance of Common Units

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

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

Non-GAAP Financial Measures

We include the following non-GAAP financial measures: Adjusted earnings before interest, taxes, depreciation and amortization, or adjusted EBITDA, distributable cash flow and gross operating margin.

Adjusted EBITDA

We define adjusted EBITDA as net income from continuing operations plus interest expense, provision for income taxes, depreciation and amortization expense, unit-based compensation, (gain) loss on noncash derivatives, transaction costs, distribution of equity investment and non-controlling interest and income (loss) on equity investment. Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:


•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and our general partner;


•	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and


•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The GAAP measures most directly comparable to adjusted EBITDA are net income from continuing operations and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income from continuing operations, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

The following tables reconcile adjusted EBITDA to the most directly comparable GAAP measure for the periods indicated.



Reconciliation of net income from continuing operations to adjusted EBITDA
	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Net income from continuing operations	$	55.4		$	81.9		$	91.1		$	134.5
Interest expense	22.4			13.2			41.3			18.0
Depreciation and amortization	97.7			74.5			189.0			123.0
Income from equity investments	(5.9		)	(4.5		)	(9.7		)	(8.7		)
Distributions from equity investments	12.4			3.0			19.2			5.7
Unit-based compensation	7.6			5.7			21.4			9.7
Income taxes	0.7			1.2			1.9			20.8
Payments under onerous performance obligation offset to other current and long-term liabilities	(4.5		)	(4.5		)	(9.0		)	(5.7		)
Other (a)	4.6			0.8			15.4			2.1
Adjusted EBITDA before non-controlling interest	190.4			171.3			360.6			299.4
Non-controlling interest share of adjusted EBITDA	0.1			(0.1		)	—			(0.1		)
Transferred interest adjusted EBITDA (b)	(15.6		)	(58.0		)	(55.8		)	(72.4		)
Predecessor adjusted EBITDA (c)	—			—			—			(82.8		)
Adjusted EBITDA, net to EnLink Midstream Partners, LP	$	174.9		$	113.2		$	304.8		$	144.1

_________________________________________________


(a)	Includes financial derivatives marked-to-market, accretion expense associated with asset retirement obligations, reimbursed employee costs from Devon and LPC, and acquisition transaction costs.


(b)	Represents recast E2, EMH and VEX adjusted EBITDA prior to the date of the drop down of the respective assets or interests from ENLC and Devon.


(c)	Represents Predecessor's adjusted EBITDA for the period from January 1, 2014 through March 7, 2014.

Distributable Cash Flow

We define distributable cash flow as net cash provided by operating activities plus adjusted EBITDA, net to EnLink Midstream Partners, LP, less interest expense, litigation settlement adjustment, interest rate swap proceeds, cash taxes and other, maintenance capital expenditures and Predecessor adjusted EBITDA. Distributable cash flow is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and our general partner.

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

The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Distributable cash flow should not be considered an alternative to, or more meaningful than, net income from continuing operations, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Distributable cash flow may not be comparable to similarly titled measures of other companies because other entities may not calculate distributable cash flow in the same manner. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as distributable cash flow, to evaluate our overall performance.



Reconciliation of net cash provided by operating activities to Adjusted EBITDA and Distributable Cash Flow
	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Net cash provided by operating activities	$	120.6		$	99.6		$	292.3		$	221.4
Interest expense, net (1)	23.0			13.5			44.7			18.6
Unit-based compensation (2)	—			—			—			2.8
Current income tax	0.7			0.7			1.9			0.8
Distributions from equity investments in excess of earnings	4.8			2.4			8.9			5.0
Other (3)	1.9			0.2			8.8			(0.7		)
Changes in operating assets and liabilities which provided cash:
Accounts receivable, accrued revenues, inventories and other	61.5			41.0			(57.3		)	(5.0		)
Accounts payable, accrued purchases and other (4)	(22.1		)	13.9			61.3			56.5
Adjusted EBITDA before non-controlling interest	190.4			171.3			360.6			299.4
Non-controlling interest share of adjusted EBITDA	0.1			(0.1		)	—			(0.1		)
Transferred interest adjusted EBITDA (5)	(15.6		)	(58.0		)	(55.8		)	(72.4		)
Predecessor adjusted EBITDA (6)	—			—			—			(82.8		)
Adjusted EBITDA, net to EnLink Midstream Partners, LP	$	174.9		$	113.2		$	304.8		$	144.1
Interest expense	(22.4		)	(13.2		)	(41.3		)	(18.0		)
Non-cash adjustment for mandatorily redeemable non-controlling interest	(0.7		)	—			(3.3		)	—
Interest rate swap (7)	(3.6		)	—			(3.6		)	—
Cash taxes and other	(0.6		)	(0.8		)	(1.6		)	(0.8		)
Maintenance capital expenditures (8)	(13.5		)	(4.3		)	(22.3		)	(5.8		)
Distributable cash flow	$	134.1		$	94.9		$	232.7		$	119.5


(1)	Net of amortization of debt issuance costs, discount and premium, and valuation adjustment for mandatorily redeemable non-controlling interest included in interest expense.


(2)	Represents Predecessor stock-based compensation contributed through equity and reflected in net distributions to Predecessor in cash flows from financing activities in the Consolidated Statements of Cash Flows.


(3)	Includes transaction costs and reimbursed employee costs from Devon and LPC.


(4)	Net of payments under onerous performance obligation offset to other current and long-term liabilities.


(5)	Represents recast E2, EMH and VEX adjusted EBITDA prior to the date of the drop down of the respective assets or interests from ENLC and Devon as applicable.


(6)	Represents Predecessor's adjusted EBITDA for the period from January 1, 2014 through March 7, 2014.


(7)	During the second quarter of 2015, we entered into interest rate swap arrangements to mitigate our exposure to interest rate movements prior to our note issuances. The gain on settlement of the interest rate swaps was considered excess proceeds for the note issuance, and therefore, excluded from distributable cash flow.

(8)

Maintenance capital expenditures presented in the Partnership’s reconciliation to distributable cash flows above include only (i) expenditures of the Partnership incurred at or after March 7, 2014 and (ii) the Partnership's interest of the expenditures of Midstream Holdings incurred at or after March 7, 2014. Maintenance capital expenditures prior to March 7, 2014 of $4.6 million were excluded from the reconciliation to distributable cash flow because they represent the cash flows of the Predecessor which were not available for distribution. Prior to March 7, 2014 these assets were owned by Devon, and therefore, all cash flow from these assets were distributed to Devon.

Gross Operating Margin

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

to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Total gross operating margin	$	306.3		$	265.3		$	589.4		449.5

Deduct:
Operating expenses	(109.1		)	(73.9		)	(207.6		)	(120.6		)
General and administrative expenses	(27.0		)	(25.8		)	(68.8		)	(41.3		)
Depreciation and amortization	(97.7		)	(74.5		)	(189.0		)	(123.0		)
Operating income	$	72.5		$	91.1		$	124.0		$	164.6

Results of Operations

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

Items Affecting Comparability of Our Financial Results

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

•

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


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


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

•

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


•	The Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. Due to Midstream Holdings’ status as a partnership, Midstream Holdings is not subject to U.S. federal income tax or certain state income taxes.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions, except volumes)
Texas Segment
Revenues	$	268.0		$	229.1		$	478.8		$	612.9
Cost of sales	(118.4		)	(76.1		)	(185.6		)	(333.4		)
Total gross operating margin	$	149.6		$	153.0		$	293.2		$	279.5
Louisiana Segment
Revenues	$	481.7		$	553.8		$	919.0		$	699.8
Cost of sales	(418.2		)	(508.1		)	(789.1		)	(641.6		)
Total gross operating margin	$	63.5		$	45.7		$	129.9		$	58.2
Oklahoma Segment
Revenues	$	40.7		$	47.2		$	86.3		$	221.7
Cost of sales	(2.0		)	—			(7.1		)	(133.9		)
Total gross operating margin	$	38.7		$	47.2		$	79.2		$	87.8
Crude and Condensate Segment
Revenues	$	518.9		$	119.7		$	786.0		$	144.5
Cost of sales	(465.6		)	(98.7		)	(700.3		)	(117.6		)
Total gross operating margin	$	53.3		$	21.0		$	85.7		$	26.9
Corporate
Revenues	$	(34.8	)	$	(22.6	)	$	(55.1	)	$	(28.6	)
Cost of sales	36.0			21.0			56.5			25.7
Total gross operating margin	$	1.2		$	(1.6	)	$	1.4		$	(2.9	)
Total
Revenues	$	1,274.5		$	927.2		$	2,215.0		$	1,650.3
Cost of sales	(968.2		)	(661.9		)	(1,625.6		)	(1,200.8		)
Total gross operating margin	$	306.3		$	265.3		$	589.4		$	449.5

Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)	2,727,800			2,994,400			2,739,300			2,977,200
Processing (MMBtu/d)	1,262,000			1,156,700			1,199,500			1,146,600
Louisiana (2)
Gathering and Transportation (MMBtu/d)	1,383,300			429,600			1,369,400			426,900
Processing (MMBtu/d)	520,400			591,900			477,600			602,800
NGL Fractionation (Gals/d)	5,862,800			3,360,400			5,748,200			3,355,100
Oklahoma (3)
Gathering and Transportation (MMBtu/d)	413,000			512,500			422,400			461,900
Processing (MMBtu/d)	268,200			458,400			312,100			441,600
Crude and Condensate (2)
Crude Oil Handling (Bbls/d)	141,000			16,300			122,400			16,000
Brine Disposal (Bbls/d)	3,700			5,200			3,700			5,300

__________________________________________________


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


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


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

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

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

•

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

•

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

•

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

•

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

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




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


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

•

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


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

•

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

General and Administrative Expenses. General and administrative expenses were $27.0 million for the three months ended June 30, 2015 as compared to $25.8 million for the three months ended June 30, 2014, an increase of $1.2 million, or 4.7%. The primary contributors to the total increase are as follows:

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

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

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

Depreciation and Amortization. Depreciation and amortization expenses were $97.7 million for the three months ended June 30, 2015 as compared to $74.5 million for the three months ended June 30, 2014, an increase of $23.2 million, or 31.1%. Of this increase in depreciation and amortization expenses, $7.5 million is attributable to the acquisition of the Coronado assets in March 2015, $3.0 million is attributable to the LPC acquisition in January 2015 and $3.0 million is attributable to the acquisition of the Gulf Coast natural gas pipeline assets in November 2014. The remaining increase in depreciation and amortization expense of $9.7 million primarily relates to new assets placed in service, of which $3.5 million is attributable to our Bearkat assets, $2.7 million is attributable to the additional E2 assets and $4.8 million is attributable to the Cajun Sibon expansion.

Interest Expense. Interest expense was $22.4 million for the three months ended June 30, 2015 as compared to $13.2 million for the three months ended June 30, 2014, an increase of $9.2 million, or 69.7%. Of the increase in interest expense, $13.4 million is attributable to an increase in average debt in 2015 compared to 2014 and $2.7 million is attributable to a decrease in capitalized interest. This increase was partially offset by a $2.6 million decrease due to a decline in average interest rates, a gain on the settlement of interest rate swaps of $3.6 million and an increase in non-cash interest income of $0.7 million attributable to the valuation of our mandatorily redeemable non-controlling interest. Net interest expense consists of the following (in millions):



	Three Months Ended June 30,
	2015			2014
Senior notes	$	25.6		$	16.4
Partnership credit facility	2.2			0.8
Capitalized interest	(1.6		)	(4.3		)
Amortization of debt issue cost, discount and premium	0.1			(0.5		)
Cash settlements on interest rate swaps	(3.6		)	—
Mandatory redeemable non-controlling interest	(0.7		)	—
Other	0.4			0.8
Total	$	22.4		$	13.2

Income Tax Expense. Income tax expense was $0.7 million for the three months ended June 30, 2015 as compared to income tax expense of $1.2 million for the three months ended June 30, 2014, a decrease of $0.5 million. This decrease primarily relates to a downward revision in our estimated Texas franchise tax.

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

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

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

General and Administrative Expenses. General and administrative expenses were $68.8 million for the six months ended June 30, 2015 as compared to $41.3 million for the six months ended June 30, 2014, an increase of $27.5 million, or 66.6%. Of this increase in general and administrative expenses, $18.8 million is attributable to the legacy Partnership assets, $6.0 million is attributable to certain bonuses paid in March 2015 in the form of unit awards that immediately vested and $4.1 million is attributable to transaction costs related to LPC, Coronado and Gulf Coast asset acquisitions. The increase in general and administrative expenses was partially offset by a $2.4 million decrease attributable to Midstream Holdings. Prior to March 7, 2014, general and administrative expenses were allocated to Midstream Holdings by Devon.

Depreciation and Amortization. Depreciation and amortization expenses were $189.0 million for the six months ended June 30, 2015 as compared to $123.0 million for the six months ended June 30, 2014, an increase of $66.0 million, or 53.7%. Of this increase in depreciation and amortization expenses, $21.8 million is attributable to the legacy Partnership assets acquired in March 2014, $21.0 million is attributable to the LPC, Coronado and Gulf Coast asset acquisitions and $25.4 million is attributable to new assets placed in service. This increase was partially offset by a decrease of $2.0 million in depreciation and amortization expenses related to Midstream Holdings due to the change in depreciation methodology from the units-of-production method to the straight-line method.

Interest Expense. Interest expense was $41.3 million for the six months ended June 30, 2015 as compared to $18.0 million for the six months ended June 30, 2014, an increase of $23.3 million, or 129.4%. Of the increase in interest expense, $16.2 million is attributable to the number of days debt was outstanding in 2015 compared to 2014 because Midstream Holdings did not have any borrowings prior to March 7, 2014. Interest expense for the six months ended June 30, 2015 includes interest expense for 181 days as compared to 116 days for the six months ended June 30, 2014 (days from March 7, 2014 through June 30, 2014). Further, average debt outstanding increased in 2015 as compared to 2014, which increased interest expense $14.7 million which was partially offset by $3.4 million due to a decrease in average interest rates. This increase was partially offset by an increase due to a gain on the settlement of interest rate swaps of $3.6 million and an increase in non-cash interest income of $3.3 million attributable to the valuation of our mandatorily redeemable non-controlling interest. Net interest expense consists of the following (in millions):



	Six Months Ended June 30,
	2015			2014
Senior notes	$	45.9		$	21.7
Partnership credit facility	4.5			1.4
Capitalized interest	(2.9		)	(5.3		)
Amortization of debt issue cost, discount and premium	(0.1		)	(0.7		)
Cash settlements on interest rate swaps	(3.6		)	—
Mandatory redeemable non-controlling interest	(3.3		)	—
Other	0.8			0.9
Total	$	41.3		$	18.0

Income Tax Expense. Income tax expense was $1.9 million for the six months ended June 30, 2015 as compared to income tax expense of $20.8 million for the six months ended June 30, 2014, a decrease of $18.9 million. This decrease primarily relates to taxable income related to the Predecessor, which was a taxable entity prior to the business combination on March 7, 2014.

Critical Accounting Policies

Information regarding the Partnership’s Critical Accounting Policies is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014, as recast on the Partnership's Current Report on Form 8-K dated May 28, 2015, except as described below.

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

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

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $292.3 million for the six months ended June 30, 2015 compared to $221.4 million for the six months ended June 30, 2014. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):



	Six Months Ended June 30,
	2015			2014
Operating cash flows before working capital	$	305.3		$	277.3
Changes in working capital	$	(13.0	)	$	(55.9	)

The primary reason for the increase in operating cash flows before working capital of $28.0 million from 2014 to 2015 relates to an increase in gross operating margin from the acquired legacy Partnership, Coronado, VEX, LPC, E2 and Gulf Coast assets. Gross operating margin also increased due to start-up operations of organic growth projects. The change in working capital for 2015 related to fluctuations in trade receivable and payable balances is due to timing of collection and payments and changes in inventory balances due to normal operating fluctuations. Further, prior to March 7, 2014, all cash receipts for the Predecessor were deposited into Devon’s bank accounts, and all cash disbursements were made from these accounts. Cash transactions handled by Devon were reflected in intercompany advances between Devon and the Predecessor, all of which were settled through an adjustment to equity and reflected in cash flows from financing activities. Subsequent to March 7, 2014, Midstream Holdings handles all of its cash transactions and the changes in working capital are reflected in our cash flows from operating activities.

Cash Flows from Investing Activities. Net cash used in investing activities was $665.0 million for the six months ended June 30, 2015 and $431.3 million for the six months ended June 30, 2014. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):



	Six Months Ended June 30,
	2015			2014
Growth capital expenditures	$	322.9		$	322.2
Maintenance capital expenditures	26.3			14.5
Acquisition of businesses	324.8			93.9
Proceeds from sale of property	(0.1		)	—
Investment in equity investment company	—			5.7
Distribution from equity investment company in excess of earnings	(8.9		)	(5.0		)
Total	$	665.0		$	431.3

Cash Flows from Financing Activities. Net cash provided by financing activities was $371.2 million and $210.6 million for the six months ended June 30, 2015 and 2014, respectively. All Predecessor financing activities from January 1, 2014 through March 6, 2014 totaling $22.1 million are reflected in distributions to Predecessor on the statement of cash flows. Our primary financing activities excluding the period prior to March 7, 2014 consist of the following (in millions):



	Six Months Ended June 30,
	2015			2014
Net repayments on Partnership credit facility	$	(87.1	)	$	(209.7	)
Senior unsecured notes borrowings	893.3			1,190.0
Redemption of 2018 Notes	—			(767.6		)
Net borrowings on E2 credit facility	—			9.5
Net repayments under capital lease obligations	(1.6		)	(1.2		)
Debt financing costs	(9.5		)	(6.2		)
Proceeds from issuance of common units	4.1			19.9

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



	Six Months Ended June 30,
	2015		2014
Common units	$	194.6	$	51.9
General partner interest (including incentive distribution rights)	17.0		3.7
Distributions to non-controlling interests (1)	66.5		51.8
Distributions to Devon for net assets acquired	171.0		—


(1)	Represents Midstream Holdings distributions to ENLC relating to ENLC's prior ownership interest in Midstream Holdings.

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

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



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

Uncertainties. 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. 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 sued our insurers, but we have agreed to stay the matter pending resolution of our claims against Texas Brine and its 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.

Capital Requirements. We consider a number of factors in determining whether our capital expenditures are growth capital expenditures or maintenance capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income or operating capacity over

the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, gathering or processing assets, in each case to the extent such capital expenditures are expected to expand our asset base, operating capacity or our operating income.

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

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

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

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



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

__________________________________________________


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


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

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

The interest payable under the Partnership’s credit facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time. However, given the same borrowing amount and

rates in effect at June 30, 2015, the cash obligation for interest expense on the Partnership’s credit facility would be approximately $3.5 million per year or approximately $1.7 million for the remainder of 2015.

Indebtedness

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



	June 30, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2015 and December 31, 2014 was 2.3% and 1.9%, respectively	$	150.0	$	237.0
Senior unsecured notes (due 2019), net of discount of $0.4 million at June 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%	399.6		399.5
Senior unsecured notes (due 2022), including a premium of $20.4 million at June 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	182.9		184.4
Senior unsecured notes (due 2024), net of premium of $3.0 million at June 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.0		553.2
Senior unsecured notes (due 2025), net of discount of $1.3 million at June 30, 2015, which bear interest at the rate of 4.15%	748.7		—
Senior unsecured notes (due 2044), net of discount of $0.3 million at June 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%	349.7		349.7
Senior unsecured notes (due 2045), net of discount of $7.0 million at June 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	443.0		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,827.2	$	2,022.5

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

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

Recent Accounting Pronouncements

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

Disclosure Regarding Forward-Looking Statements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. We currently process gas under three main types of contractual arrangements as summarized below. Approximately 89% of our processing margins are from fixed fee based contracts for the six months ended June 30, 2015. During March 2015, the Partnership acquired processing plants from Coronado which generate gross operating margins based on percent of proceeds contracts.

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

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

Percent of proceeds contracts: Under these contracts, we receive a fee as a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under percent of proceeds contracts, but do decline during periods of low natural gas and NGL prices.

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

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

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

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

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(in millions)

July 2015 - December 2016

Ethane

974

(MBbls)

$0.2765/gal

Index

(2.6

)

July 2015 - December 2016

Propane

1,094

(MBbls)

Index

$0.8983/gal

17.5

July 2015 - June 2016

Normal Butane

132

(MBbls)

Index

$0.7184/gal

0.4

July 2015 - June 2016

Natural Gasoline

(MBbls)

Index

$1.3035/gal

0.2

July 2015 - June 2016

Natural Gas

4,107

(MMBtu/d)

$3.27/MMBtu*

Index

(0.9

)

14.6

__________________________________________________

*weighted average

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves

us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

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

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

Interest Rate Risk

We are exposed to interest rate risk on our variable rate credit facility. At June 30, 2015, we had $150.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change our annual interest expense by approximately $1.5 million for the year.

We are not exposed to changes in interest rates with respect to our senior unsecured notes due in 2019, 2022, 2024, 2025, 2044 or 2045 as these are fixed-rate obligations. The estimated fair value of our senior unsecured notes was approximately $2,606.8 million as of June 30, 2015, based on market prices of similar debt at June 30, 2015. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $229.8 million decrease in fair value of our senior unsecured notes at June 30, 2015.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes in Internal Control Over Financial Reporting

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

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

For a discussion of certain litigation and similar proceedings, please refer to Note 13, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

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

Item 6. Exhibits

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



Number		Description
2.1**	—	Contribution and Transfer Agreement, dated as of May 27, 2015, by and between EnLink Midstream Partners, LP and Acacia Natural Gas Corp I, Inc. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated May 27, 2015, filed with the Commission on May 27, 2015).
3.1	—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).
3.2	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, file No. 000-50067).
3.3	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014).
3.4	—	Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP dated July 7, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
3.5	—	Amendment No. 1 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of February 17, 2015 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated February 17, 2015, filed with the Commission on February 17, 2015).
3.6	—	Amendment No. 2 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of March 16, 2015 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 16, 2015, filed with the Commission on March 16, 2015).
3.7		Amendment No. 3 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of May 27, 2015 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated May 27, 2015, filed with the Commission on May 27, 2015).
3.8	—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
3.9	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to our Registration Statement on Form S-3, file No. 333-194465).
3.10	—	Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 2014 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
4.1	—	Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014).
4.2	—	First Supplemental Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014).
4.3	—	Second Supplemental Indenture, dated as of November 12, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K dated November 6, 2014, filed with the Commission on November 12, 2014).
4.4	—	Third Supplemental Indenture, dated as of May 12, 2015, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K dated May 7, 2015, filed with the Commission on May 12, 2015).
10.1†	—	Form of Amended and Restated Change in Control Agreement Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated June 12, 2015, filed with the Commission June 15, 2015).
31.1*	—	Certification of the Principal Executive Officer.
31.2*	—	Certification of the Principal Financial Officer.
32.1*	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.



101*	—	The following financial information from EnLink Midstream Partners, LP's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, (ii) Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014, (iii) Consolidated Statements of Changes in Partners’ Equity for the six months ended June 30, 2015, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014, and (v) the Notes to Condensed Consolidated Financial Statements.

__________________________________________________

* Filed herewith.

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

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

SIGNATURES

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



	EnLink Midstream Partners, LP

	By:	EnLink Midstream GP, LLC,
		its General Partner

	By:	/s/ MICHAEL J. GARBERDING
		Michael J. Garberding
		Executive Vice President and Chief Financial Officer

August 5, 2015