ENLK-2015.3.31-10Q

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 March 31, 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 April 24, 2015, the Registrant had 252,712,424 common units, 6,704,285 Class C Common Units and 31,618,311 Class D 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	32

3.	Quantitative and Qualitative Disclosures About Market Risk	47

4.	Controls and Procedures	49

	PART II—OTHER INFORMATION

1.	Legal Proceedings	49

1A.	Risk Factors	49

6.	Exhibits	50

ENLINK MIDSTREAM PARTNERS, LP

Condensed Consolidated Balance Sheets



	March 31, 2015		December 31, 2014
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	34.2	$	9.6
Accounts receivable:
Trade, net of allowance for bad debt	76.5		139.0
Accrued revenue and other	304.2		253.3
Related party	113.7		120.8
Fair value of derivative assets	14.3		16.7
Natural gas and NGLs inventory, prepaid expenses and other	50.7		30.8
Total current assets	593.6		570.2
Property and equipment, net of accumulated depreciation of $1,500.7 and $1,422.3, respectively	5,323.4		4,934.3
Intangible assets, net of accumulated amortization of $48.2 and $36.5, respectively	877.6		533.0
Goodwill	2,283.1		2,257.8
Fair value of derivative assets	7.6		10.0
Investments in unconsolidated affiliates	267.8		270.8
Other assets, net	17.8		16.6
Total assets	$	9,370.9	$	8,592.7

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	69.2	$	121.7
Accounts payable to related party	11.1		3.0
Accrued gas, NGLs, condensate and crude oil purchases	269.7		204.5
Fair value of derivative liabilities	3.0		3.0
Accrued interest	37.6		16.9
Other current liabilities	132.6		128.9
Total current liabilities	523.2		478.0
Long-term debt	2,493.7		2,022.5
Fair value of derivative liabilities	1.5		2.0
Asset retirement obligation	11.0		10.9
Other long-term liabilities	79.3		84.0
Deferred tax liability	77.0		73.1

Redeemable non controlling interest	4.9		—

Partners’ equity:
Common unitholders (283,991,722 units issued and outstanding at March 31, 2015 and 245,421,549 units issued and outstanding at December 31, 2014)	5,343.8		5,259.2
Class C unitholders (6,704,285 units issued and outstanding at March 31, 2015)	180.1		—
General partner interest (1,594,974 equivalent units outstanding at March 31, 2015 and 1,594,974 equivalent units outstanding at December 31, 2014)	126.5		116.6
Non controlling interest	529.9		546.4
Total partners' equity	6,180.3		5,922.2
Commitment and Contingencies (Note 13)
Total liabilities and partners’ equity	$	9,370.9	$	8,592.7

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Condensed Consolidated Statements of Operations



		Three Months Ended March 31,
		2015			2014
	(Unaudited) (In millions, except per unit amounts)
Revenues:
Revenues		$	773.1		$	232.4
Revenues - affiliates		163.0			491.9
Gain (loss) on derivative activity		0.2			(1.3		)
Total revenues		936.3			723.0
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil (1)		657.4			538.9
Operating expenses (2)		96.2			46.2
General and administrative (3)		41.9			15.3
Depreciation and amortization		90.0			48.2
Total operating costs and expenses		885.5			648.6
Operating income		50.8			74.4
Other income (expense):
Interest expense, net of interest income		(18.9		)	(4.8		)
Equity in income of equity investment		3.7			4.2
Other income (expense)		0.6			(0.7		)
Total other expense		(14.6		)	(1.3		)
Income from continuing operations before non-controlling interest and income taxes		36.2			73.1
Income tax provision		(1.2		)	(19.6		)
Net income from continuing operations		35.0			53.5
Discontinued operations:
Income from discontinued operations, net of tax		—			1.0
Discontinued operations, net of tax		—			1.0
Net income		35.0			54.5
Net income attributable to the non-controlling interest		15.4			5.3
Net income attributable to EnLink Midstream Partners, LP		$	19.6		$	49.2
Predecessor interest in net income (4)		$	—		$	35.5
General partner interest in net income		$	10.5		$	6.0
Limited partners’ interest in net income attributable to EnLink Midstream Partners, LP		$	9.0		$	7.7
Class C partners’ interest in net income attributable to EnLink Midstream Partners, LP		$	0.1		$	—
Net income attributable to EnLink Midstream Partners, LP per limited partners’ unit:
Basic per common unit		$	0.03		$	0.03
Diluted per common unit		$	0.03		$	0.03

(1) Includes $7.9 million and $325.8 million for the three months ended March 31, 2015 and 2014, respectively, of affiliate purchased gas, NGLs, condensate and crude oil.

(2) Includes $5.9 million for the three months ended March 31, 2014 of affiliate operating expenses.

(3) Includes $8.3 million for the three months ended March 31, 2014 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

Three Months Ended March 31, 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	$	5,259.2		245.4	$	—	—	$	116.6		1.6	$	546.4		$	5,922.2		$	—
Issuance of common units	182.2			38.4	180.0		6.7	—			—	—			362.2			—
Conversion of restricted units for common units, net of units withheld for taxes	(2.4		)	0.2	—		—	—			—	—			(2.4		)	—
Unit-based compensation	6.8			—	—		—	7.0			—	—			13.8			—
Contributions from Devon	2.2			—	—		—	—			—	—			2.2			—
Distributions	(92.3		)	—	—		—	(7.6		)	—	—			(99.9		)	—
Non-controlling interest contributions	—			—	—		—	—			—	2.7			2.7			—
Distributions to non-controlling interest	—			—	—		—	—			—	(45.2		)	(45.2		)	—
Adjustment related to mandatory redemption of E2 non-controlling interest	—			—	—		—	—			—	(5.4		)	(5.4		)	—
Redeemable non-controlling interest	—			—	—		—	—			—	(4.9		)	(4.9		)	4.9
Adjustment of interest in Midstream Holdings	(20.9		)	—	—		—	—			—	20.9			—			—
Net income	9.0			—	0.1		—	10.5			—	15.4			35.0			—
Balance, March 31, 2015	$	5,343.8		284.0	$	180.1	6.7	$	126.5		1.6	$	529.9		$	6,180.3		$	4.9

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Consolidated Statements of Cash Flows



	Three Months Ended March 31,
	2015			2014
	(Unaudited) (In millions)
Cash flows from operating activities:
Net income from continuing operations	$	35.0		$	53.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	90.0			48.2
Accretion expense	0.1			0.2
Deferred tax expense	—			19.5
Non-cash unit-based compensation	13.8			1.2
(Gain) loss on derivatives recognized in net income	(0.2		)	1.3
Cash settlements on derivatives	3.9			(0.6		)
Amortization of debt issue costs	0.6			0.1
Amortization of premium on notes	(0.8		)	(0.4		)
Redeemable non-controlling interest expense	(2.6		)	—
Distribution of earnings from equity investment	2.7			0.1
Equity in income of equity investments	(3.7		)	(4.2		)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	119.1			46.0
Natural gas and NGLs inventory, prepaid expenses and other	(16.3		)	(7.3		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(71.0		)	(35.1		)
Net cash provided by operating activities	170.6			122.5
Cash flows from investing activities:
Additions to property and equipment	(154.2		)	(97.8		)
Acquisition of business	(312.0		)	(29.3		)
Distribution from equity investment company in excess of earnings	4.1			2.6
Net cash used in investing activities	(462.1		)	(124.5		)
Cash flows from financing activities:
Proceeds from borrowings	959.1			1,247.9
Payments on borrowings	(487.1		)	(997.0		)
Payments on capital lease obligations	(1.0		)	(0.8		)
Decrease in drafts payable	(12.7		)	(2.6		)
Debt refinancing costs	(1.8		)	(4.9		)
Conversion of restricted units, net of units withheld for taxes	(2.4		)	—
Proceeds from issuance of common units	2.2			—
Distributions to non-controlling partners	(45.2		)	—
Contributions by non-controlling partners	2.7			0.4
Distributions to partners	(99.9		)	—
Contributions from Devon	2.2			—
Distributions to Predecessor	—			(22.1		)
Net cash provided by financing activities	316.1			220.9
Cash flow from discontinued operations:
Net cash provided by operating activities	—			5.0
Net cash used in investing activities	—			(0.6		)
Net cash used in financing activities – net distributions to Devon and non-controlling interests	—			(4.4		)
Net cash provided by discontinued operations	—			—
Net increase in cash and cash equivalents	24.6			218.9
Cash and cash equivalents, beginning of period	9.6			0.1
Cash and cash equivalents, end of period	$	34.2		$	219.0
Cash paid for interest	$	2.1		$	4.6
Cash refund for income taxes	$	0.1		$	—

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements

March 31, 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 to us in exchange for 31,618,311 Class D Common Units in the Partnership. See Note (3) - Acquisitions for further discussion.

(b)Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation and marketing, to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks and brine disposal. 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. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from producers to end users and other pipelines. 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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(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 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 on 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 quarter of 2015, the Partnership acquired assets from ENLC through drop down transactions. Because ENLC controls the Partnership through its ownership and control of the General Partner, each acquisition from ENLC was considered a transfer of net assets between entities under common control, and the Partnership also was required to recast its financial statements as of March 31, 2015 to include the activities of such assets from the date of common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from ENLC have been prepared from ENLC’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 for periods prior to the Partnership’s acquisition is allocated to the general partner.

(b) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of 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).

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, 2016, including interim periods within that reporting period, and is to be applied retrospectively, with early application not permitted. 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 three months

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

ended March 31, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

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.

(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 for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

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



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

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

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. We incurred $0.3 million of direct transaction costs for the three months ended March 31, 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 March 31, 2015, the Partnership recognized $7.1 million of revenues and $1.2 million of net income related to the assets acquired.

LPC Acquisition

On January 31, 2015, the Partnership acquired LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million. The transaction was accounted for using the acquisition method.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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)	$	106.1
Property, plant and equipment	29.3
Intangibles	49.2
Goodwill	25.3
Liabilities assumed:
Current liabilities	(106.1		)
Deferred tax liability	(3.8		)
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. The goodwill is allocated to our Crude and Condensate segment. All of the goodwill is non-deductible for tax purposes.

We incurred $0.2 million of direct transaction costs for the three months ended March 31, 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 March 31, 2015, the Partnership recognized $180.8 million of revenues and $0.9 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, the Partnership acquired Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $602.1 million, 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.

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	306.0
Intangibles	294.0
Liabilities assumed:
Current liabilities	(24.1		)
Total identifiable net assets	$	602.1

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

We incurred $3.0 million of direct transaction costs for the three months ended March 31, 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 March 31, 2015, the Partnership recognized $8.9 million of revenues and $0.6 million of net loss related to the assets acquired.

EMH Drop Down

On February 17, 2015, the Partnership acquired an additional 25% limited partner interest in Midstream Holdings (the “Transferred Interest”) from Acacia, a wholly-owned subsidiary of ENLC, in a drop down transaction (the “EMH Drop Down”). As consideration for the Transferred Interest, the Partnership issued 31,618,311 Class D Common Units in the Partnership to Acacia with an implied value of $925.0 million. The Class D 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 March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015, which was the first business day following the record date for distribution payments with respect to the distribution for the quarter ended March 31, 2015. After giving effect to the EMH Drop Down, the Partnership indirectly owns a 75% limited partner interest in Midstream Holdings, with Acacia owning the remaining 25% limited partner interest in Midstream Holdings. This acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results.

E2 Drop Down

On October 22, 2014, the Partnership acquired 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 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 following table presents the collective impact of the EMH Drop Down and the E2 Drop Down on first quarter 2014 revenue, net income, net income attributable to non-controlling interest and net income attributable to EnLink Midstream Partners, LP as presented in the Partnership's historical consolidated statements of income:



	Three Months Ended March 31, 2014
	Partnership Historical		EMH		E2			Combined
	(in millions)
Revenues	$	722.5	$	—	$	0.5		$	723.0
Net income (loss)	$	54.6	$	—	$	(0.1	)	$	54.5
Net income attributable to non-controlling interest	$	10.5	$	5.2	$	—		$	5.3
Net income attributable to EnLink Midstream Partners, LP	$	44.1	$	5.2	$	(0.1	)	$	49.2
General partner interest in net income	$	0.9	$	5.2	$	(0.1	)	$	6.0

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

Devon Merger

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 120,542,441 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 Fractionator (“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 March 31, 2014, the Partnership recognized $199.4 million of revenues and $1.8 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 months ended March 31, 2015 and 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, EMH 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 March 31,
	2015		2014
	(in millions, except for per unit data)
Pro forma total revenues (1)	$	1,058.4	$	1,379.8
Pro forma net income	$	29.8	$	34.7
Pro forma net income attributable to EnLink Midstream Partners, LP	$	14.4	$	19.2
Pro forma net income per common unit:
Basic	$	0.01	$	(0.01	)
Diluted	$	0.01	$	(0.01	)

(1)Effective March 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 comparing the implied fair value to the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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.



	March 31, 2015		December 31, 2014
	(in millions)
Texas	$	1,168.2	$	1,168.2
Louisiana	786.8		786.8
Oklahoma	190.3		190.3
Crude and Condensate	137.8		112.5
Total	$	2,283.1	$	2,257.8

The change in goodwill is related to a $25.3 million increase in goodwill related to the LPC acquisition. 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 ten 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
March 31, 2015
Customer relationships	$	925.8	$	(48.2	)	$	877.6
December 31, 2014
Customer relationships	$	569.5	$	(36.5	)	$	533.0

The weighted average amortization period for intangible assets is 11.1 years. Amortization expense for intangibles was approximately $11.5 million and $1.9 million for the three months ended March 31, 2015 and 2014, respectively.

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



2015	$	51.7
2016	67.0
2017	67.0
2018	67.0
2019	66.1
Thereafter	558.8
Total	$	877.6

(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. Prior to March 7, 2014, these 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. Management believes these

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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.

Midstream Holdings, in which the Partnership holds a 75% economic interest as of March 31, 2015, conducts business with Devon pursuant to the gathering and processing agreements described below. The Partnership also continues to maintain a relationship originally established with Devon as a customer prior to the business combination, as described in more detail below.

Gathering and Processing Agreements

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.

On August 29, 2014, Gas Services assigned its 10-year gathering and processing agreement 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. Such assignment was effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, Linn Energy began performing Gas Services' obligations under the agreement, which remains in full force and effect. The assignment of this agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma.

Historical Customer Relationship 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 certain of the Partnership's subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with such Devon subsidiaries. The terms of these agreements vary, but the agreements expire between March 2015 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, one of the Partnership's subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership's subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee. These NGL purchase and sale agreements have month-to-month terms.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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, including IT, accounting, pipeline integrity, compliance management and procurement services, and the Partnership provides certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. Operating expenses related to the transition service agreement were $0.3 million for the three months ended March 31, 2014. We received $0.1 million from Devon under the transition services agreement for the three months ended March 31, 2015. Substantially all services under the transition services agreement were completed during 2014.

GCF Agreement

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 Devon agreed, from and after the closing of the business combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% interest in GCF, which owns a fractionation facility in Mont Belvieu, Texas.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

Acacia Transportation Agreement

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.

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):



	Three Month Ended March 31,
	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	(26.2		)
Total net distributions per equity	$	(48.3	)

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	$	(92.6	)

For the three months ended March 31, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 17.4% and 68.0% of the Partnership's revenues for the three months ended March 31, 2015 and 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $111.0 million as of March 31, 2015 and $120.8 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $11.1 million as of March 31, 2015 and $3.0 million as of December 31, 2014.

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the three months ended March 31, 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 three months ended March 31, 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)

(6) Long-Term Debt

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



	March 31, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2015 and December 31, 2014 was 1.6% and 1.9%, respectively	$	709.0	$	237.0
Senior unsecured notes (due 2019), net of discount of $0.5 million, which bear interest at the rate of 2.70%	399.5		399.5
Senior unsecured notes (due 2022), including a premium of $21.1 million at March 31, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	183.7		184.4
Senior unsecured notes (due 2024), net of premium of $3.1 million at March 31, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.1		553.2
Senior unsecured notes (due 2044), net of discount of $0.3 million, which bear interest at the rate of 5.60%	349.7		349.7
Senior unsecured notes (due 2045), net of discount of $1.6 million at March 31, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	298.4		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,493.7	$	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 March 31, 2015, there were $2.9 million in outstanding letters of credit and $709.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $788.1 million available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms of the 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. 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)

(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 any time suspend solicitation and offers under the BMO EDA. For the three months ended March 31, 2015, the Partnership sold an aggregate of 0.1 million common units under the BMO EDA, generating proceeds of approximately $2.2 million (net of less than $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of March 31, 2015, approximately $339.7 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.

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 were only entitled to 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 and are included with common units outstanding as of March 31, 2015.

(d) 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)

A summary of the distribution activity relating to the common units for the three months ended March 31, 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)	$	0.38	May 14, 2015

(1) The Partnership declared a partial first quarter 2015 distribution on its Class D Common Units of $0.18 per unit to be paid on May 14, 2015. Distributions declared 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.

(e) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income 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 March 31,
	2015			2014*
Limited partners’ interest in net income	$	9.0		$	7.7
Distributed earnings allocated to:
Common units (1) (2)	$	99.5		$	51.3
Unvested restricted units (1)	0.4			0.2
Total distributed earnings	$	99.9		$	51.5
Undistributed loss allocated to:
Common units (2)	$	(90.5	)	$	(43.7	)
Unvested restricted units	(0.4		)	(0.1		)
Total undistributed loss	$	(90.9	)	$	(43.8	)
Net income allocated to:
Common units (2)	$	9.0		$	7.6
Unvested restricted units	—			0.1
Total limited partners’ interest in net income	$	9.0		$	7.7
Basic and diluted net income per unit:
Basic	$	0.03		$	0.03
Diluted	$	0.03		$	0.03

* The three months ended March 31, 2014 amounts consist only of the period from March 7, 2014 through March 31, 2014.

(1) Three months ended March 31, 2015 and 2014 represents a declared distribution of $0.38 per unit payable on May 14, 2015 and declared distribution of $0.36 per unit for common units paid on May 14, 2014.

(2) Includes declared partial distribution of $0.18 per unit for Class D Common Units payable May 14, 2015 and 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)

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 March 31,
Basic weighted average units outstanding:	2015	2014*
Weighted average limited partner basic common units outstanding	246.7	109.0
Weighted average Class B Common Units outstanding	—	120.5
Weighted average Class C Common Units outstanding	1.1	—
Weighted average Class D Common Units outstanding	15.1	—
Total weighted average limited partner common units outstanding	262.9	229.5
Diluted weighted average units outstanding:
Weighted average limited partner basic common units outstanding	262.9	229.5
Dilutive effect of restricted units issued	0.4	0.6
Total weighted average limited partner diluted common units outstanding	263.3	230.1

* The three months ended March 31, 2014 amounts consist only of the period from March 7, 2014 through March 31, 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(d). 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 March 31,
	2015			2014*
Income allocation for incentive distributions	$	8.8		$	1.4
Unit-based compensation attributable to ENLC’s restricted units	(7.0		)	(0.6		)
General Partner interest in net income	0.1			0.1
General Partner interest in drop down transactions	8.6			5.1
General Partner share of net income	$	10.5		$	6.0

* The three months ended March 31, 2014 amounts consist only of the period from March 7, 2014 through March 31, 2014.

(8) Asset Retirement Obligations

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



	March 31, 2015			March 31, 2014
	(in millions)
Beginning asset retirement obligations	$	19.1		$	7.7
Revisions to existing liabilities	(3.9		)	—
Liabilities acquired	—			0.5
Accretion	0.1			0.2
Liabilities settled	(3.2		)	—
Ending asset retirement obligations	$	12.1		$	8.4

Asset retirement obligations of $1.1 million as of March 31, 2015 are included in Other Current Liabilities.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(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 March 31, 2015 and 2014 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at March 31, 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
March 31, 2015
Distributions	$	2.7	$	4.1	$	6.8
Equity in income	$	3.3	$	0.4	$	3.7

March 31, 2014
Distributions (1)	$	—	$	2.7	$	2.7
Equity in income	$	4.1	$	0.1	$	4.2

(1) Includes income and distributions for the period from March 7, 2014 through March 31, 2014 for HEP.

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



	March 31, 2015		December 31, 2014
Gulf Coast Fractionators	$	54.7	$	54.1
Howard Energy Partners	213.1		216.7
Total investments in unconsolidated affiliates	$	267.8	$	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.

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 and Midstream Holdings. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions):



	Three Months Ended March 31,
	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	11.9		1.0
Cost of unit-based compensation charged to operating expense	1.9		0.2
Total amount charged to income	$	13.8	$	4.0


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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(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 three months ended March 31, 2015 is provided below:



	Three Months Ended March 31, 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	542,723			27.07
Vested*	(244,998		)	28.62
Forfeited	(55,193		)	31.48
Non-vested, end of period	1,264,723			$	29.96
Aggregate intrinsic value, end of period (in millions)	$	31.3

* Vested units include 84,860 units withheld for payroll taxes paid on behalf of employees.

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

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three months ended March 31, 2015 are provided below (in millions):



	Three Months Ended March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:	2015
Aggregate intrinsic value of units vested	$	6.8
Fair value of units vested	$	7.0

As of March 31, 2015, there was $27.3 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 2.2 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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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.



	Three Months Ended March 31,
	2015
Beginning TSR Price	$	27.68
Risk-free interest rate	0.99		%
Volatility factor	33.01		%
Distribution yield	5.66		%

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



	Three Months Ended March 31, 2015
EnLink Midstream Partners, LP Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	108,713		36.18
Vested	—		—
Non-vested, end of period	108,713		$	36.18
Aggregate intrinsic value, end of period (in millions)	$	2.7

As of March 31, 2015 there was $3.7 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 2.1 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 activities for the three months ended March 31, 2015 is provided below:



	Three Months Ended March 31, 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	462,875			31.74
Vested*	(240,760		)	35.71
Forfeited	(47,473		)	36.60
Non-vested, end of period	1,161,114			$	35.21
Aggregate intrinsic value, end of period (in millions)	$	37.8

* Vested units include 77,519 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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)



	Three Months Ended March 31,
EnLink Midstream, LLC Restricted Incentive Units:	2015
Aggregate intrinsic value of units vested	$	8.3
Fair value of units vested	$	8.6

As of March 31, 2015, there was $27.4 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 2.1 years.

(e) EnLink Midstream, LLC's Performance Units

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



	Three Months Ended March 31,
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.



	Three Months Ended March 31, 2015
EnLink Midstream, LLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-Vested, beginning of period	—		$	—
Granted	96,963		41.31
Vested	—		—
Non-vested, end of period	96,963		$	41.31
Aggregate intrinsic value, end of period (in millions)	$	3.2

As of March 31, 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 2.1 years.

(11) Derivatives

Commodity Swaps

The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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 consolidated statements of operations relating to commodity swaps are as follows for the three months ended March 31, 2015 and 2014 (in millions):



	Three Months Ended March 31,
	2015			2014*
Change in fair value of derivatives	$	(3.7	)	$	(0.7	)
Realized gain (loss) on derivatives	3.9			(0.6		)
Gain (loss) on derivative activity	$	0.2		$	(1.3	)

* The three months ended March 31, 2014 amounts consist only of the period from March 7, 2014 through March 31, 2014.

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



	March 31, 2015			December 31, 2014
Fair value of derivative assets — current	$	14.3		$	16.7
Fair value of derivative assets — long term	7.6			10.0
Fair value of derivative liabilities — current	(3.0		)	(3.0		)
Fair value of derivative liabilities — long term	(1.5		)	(2.0		)
Net fair value of derivatives	$	17.4		$	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 March 31, 2015. The remaining term of the contracts extend no later than December 2016.



			March 31, 2015
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(54.7	)	$	21.7
NGL (long contracts)	Swaps	Gallons	44.6		(4.1		)
Natural Gas (short contracts)	Swaps	MMBtu	(0.6	)	0.1
Natural Gas (long contracts)	Swaps	MMBtu	0.4		(0.3		)
Condensate (short contracts)	Swaps	MMbbls	—		(0.1		)
Condensate (long contracts)	Swaps	MMbbls	—		0.1
Total fair value of derivatives					$	17.4

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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 March 31, 2015 of $21.9 million would be reduced to $17.4 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 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
March 31, 2015	$	11.3	$	6.1	$	—	$	17.4

(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):



	March 31, 2015 Level 2		December 31, 2014 Level 2
Commodity Swaps*	$	17.4	$	21.7
Total	$	17.4	$	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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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):



	March 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	2,493.7	$	2,571.2	$	2,022.5	$	2,026.1
Obligations under capital leases	$	19.3	$	18.7	$	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 $709.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of March 31, 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 March 31, 2015, the Partnership had borrowings totaling $399.5 million, $553.1 million, $349.7 million and $298.4 million net of discount, under the senior unsecured notes due in 2019, 2024, 2044 and 2045, respectively, with a fixed rate of 2.70%, 4.40%, 5.60% and 5.05%, respectively. As of December 31, 2014, the Partnership had borrowings totaling $399.5 million, $553.2 million, $349.7 million, and $298.3 million net of discount under the senior unsecured notes due in 2019, 2024, 2044 and 2045, respectively, with a fixed rate of 2.70%, 4.40%, 5.60% and 5.05%, respectively. Additionally, the Partnership had borrowings of $183.7 million and $184.4 million, including premium, under the senior unsecured notes due in 2022 with a fixed rate of 7.125% as of March 31, 2015 and December 31, 2014, respectively. The fair value of all senior unsecured notes as of March 31, 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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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 or results of operations.

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 or financial condition.

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

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

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 this damage. 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 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.

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(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 the west Texas, Louisiana and ORV ("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 acquisition of LPC, 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:



	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
	(In millions)
Three Months Ended March 31, 2015
Sales to external customers	$	70.7		$	429.7		$	9.0		$	263.7		$	—		$	773.1
Sales to affiliates	140.6			11.9			34.9			—			(24.4		)	163.0
Purchased gas, NGLs, condensate and crude oil	(66.5		)	(376.4		)	(3.4		)	(235.5		)	24.4			(657.4		)
Operating expenses	(48.5		)	(22.5		)	(7.9		)	(17.3		)	—			(96.2		)
Gain on derivative activity	—			—			—			—			0.2			0.2
Segment profit	$	96.3		$	42.7		$	32.6		$	10.9		$	0.2		$	182.7
Depreciation and amortization	$	(36.5	)	$	(27.4	)	$	(13.5	)	$	(11.1	)	$	(1.5	)	$	(90.0	)
Goodwill	$	1,168.2		$	786.8		$	190.3		$	137.8		$	—		$	2,283.1
Capital expenditures	$	73.7		$	17.8		$	5.4		$	52.3		$	4.3		$	153.5
Three Months Ended March 31, 2014
Sales to external customers	$	48.3		$	152.5		$	11.5		$	20.1		$	—		$	232.4
Sales to affiliates	335.9			0.5			162.9			—			(7.4		)	491.9
Purchased gas, NGLs, condensate and crude oil	(257.7		)	(140.5		)	(133.8		)	(14.3		)	7.4			(538.9		)
Operating expenses	(31.7		)	(5.1		)	(6.7		)	(2.7		)	—			(46.2		)
Loss on derivative activity	—			—			—			—			(1.3		)	(1.3		)
Segment profit	$	94.8		$	7.4		$	33.9		$	3.1		$	(1.3	)	$	137.9
Depreciation and amortization	$	(27.2	)	$	(5.2	)	$	(14.2	)	$	(1.5	)	$	(0.1	)	$	(48.2	)
Goodwill	$	1,256.7		$	885.1		$	190.3		$	106.0		$	—		$	2,438.1
Capital expenditures	$	25.1		$	22.1		$	10.2		$	5.0		$	5.5		$	67.9

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

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



	March 31, 2015		December 31, 2014
Segment Identifiable Assets:	(In millions)
Texas	$	3,958.7	$	3,302.9
Louisiana	3,175.7		3,316.5
Oklahoma	883.4		892.8
Crude and Condensate	1,036.7		762.5
Corporate	316.4		318.0
Total identifiable assets	$	9,370.9	$	8,592.7

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



	Three Months Ended March 31,
	2015			2014
Segment profits	$	182.7		$	137.9
General and administrative expenses	(41.9		)	(15.3		)
Depreciation and amortization	(90.0		)	(48.2		)
Operating income	$	50.8		$	74.4

(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):



	Three Months Ended March 31,
	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

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements-(Continued)

(16) Supplemental Cash Flow Information

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



	Three Months Ended March 31,
	2015
	(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)	$	20.9

(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' interest acquired on February 17, 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.

(17) Subsequent Event

Dropdown of VEX pipeline. On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets (“VEX”) 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 (the “Consideration Units”) 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 multi-grade crude oil pipeline. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks.

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 9,100 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 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 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”) and our crude oil operations in the Permian Basin; 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 purchase and resell natural gas, NGLs, crude oil and condensate for a margin or to gather, process, transport or market natural gas, NGLs, crude oil and condensate for a fee. In addition, we earn a volume based fee for brine disposal services and condensate stabilization. We define gross operating margin as operating revenue minus cost of purchased gas, NGLs, condensate and crude oil. 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.

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 eight primary sources:

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

•processing natural gas at our processing plants;

•fractionating and marketing the recovered NGLs;

•providing compression services;

•purchasing and reselling crude oil and condensate;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services; and

•providing brine disposal services.

We generally gather or transport gas owned by others through our facilities for a fee, or we 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 market index. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins 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. However, 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 margin. Changes in the basis spread can increase or decrease our margins.

We have made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect 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 March 31, 2015, the balance sheet reflects a liability of $76.2 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the cash losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

The majority of our NGL fractionation business, which includes transportation, fractionation, and storage, is under fee-based arrangements. We are typically paid a fixed fee based on the volume of NGLs transported, fractionated or stored. On our Cajun-Sibon pipeline, we buy the mixed NGL stream from our suppliers for an indexed-based price for the component NGLs with a deduction for our fractionation fee. After the NGLs are fractionated, we 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 margins we realize 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, or we 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 market index. We execute all purchases and sales substantially concurrently, thereby establishing the basis for the margin we will receive for each crude oil and condensate transaction. Additionally, we provide crude oil, condensate and brine services on a volume basis.

We also realize gross operating margins from our processing services primarily through three different contract arrangements: processing margins ("margin"), 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 the 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, Acacia contributed a 25% interest in Midstream Holdings to us in exchange for 31,618,311 of our Class D Common Units. See “Recent Developments.”

Recent Developments

Acquisitions

Coronado Midstream. On March 16, 2015, the Partnership acquired all of the 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 $600.0 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 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 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 Victoria Express Pipeline and related truck terminal and storage assets (“VEX”) 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 million (the “Consideration Units”) and the Partnership’s assumption of up to $40 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 (bpd) and, following completion of currently-underway expansion projects, will have capacity of approximately 90,000 bpd. Other VEX assets at the destination of the pipeline include an eight-bay truck unloading terminal, 200,000 barrels of above-ground storage, of which 50,000 barrels are under construction, and rights to barge loading docks.

Midstream Holdings Drop Down. On February 17, 2015, the Partnership acquired a 25% limited partner interest in Midstream Holdings (the “Transferred Interest”) from Acacia, a wholly-owned subsidiary of ENLC, in a drop-down transaction (the “EMH Drop Down”). As consideration for the Transferred Interest, the Partnership issued 31,618,311 Class D Common Units in the Partnership to Acacia. The Class D Common Units are substantially similar in all respects to the Partnership’s common units, except that they will only be entitled to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015, which was the first business day following the record date for distribution payments with respect to the distribution for the quarter ended March 31, 2015. After giving effect to the EMH Drop-Down, the Partnership indirectly owns a 75% limited partner interest in Midstream Holdings, with Acacia owning the remaining 25% limited partner interest in 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 is currently evaluating whether to proceed with current timetable or delay the construction of the pipeline to a more optimal time. 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 Partnership also expects to own and operate six natural gas compression and condensate stabilization facilities in Noble, Belmont, and Guernsey counties in Ohio. 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 partially operating in April of 2015.

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 three months ended March 31, 2015, the Partnership sold an aggregate of 0.1 million common units under the BMO EDA, generating proceeds of approximately $2.2 million (net of approximately $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of March 31, 2015, approximately $339.7 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 March 31,
	2015			2014
	(in millions)
Net income from continuing operations	$	35.0		$	53.5
Interest expense	18.9			4.8
Depreciation and amortization	90.0			48.2
Income from equity investments	(3.7		)	(4.2		)
Distributions from equity investments	6.8			2.7
Unit-based compensation	13.8			4.0
Income taxes	1.2			19.6
Payments under onerous performance obligation offset to other current and long-term liabilities	(4.5		)	(1.2		)
Other (a)	10.7			1.5
Adjusted EBITDA before non-controlling interest	168.2			128.9
Non-controlling interest share of adjusted EBITDA	(25.1		)	(7.5		)
Transferred interest adjusted EBITDA (b)	(13.2		)	(7.8		)
Predecessor adjusted EBITDA	—			(82.8		)
Adjusted EBITDA, net to EnLink Midstream Partners, LP	$	129.9		$	30.8

_________________________________________________

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

(b) Represents recast E2 and recast EMH adjusted EBITDA.

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, 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.

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 March 31,
	2015			2014
	(in millions)
Net cash provided by operating activities	$	170.6		$	122.5
Interest expense, net (1)	21.7			5.1
Unit-based compensation (2)	—			2.8
Current income tax (benefit)	1.2			0.1
Distributions from equity investments in excess of earnings	4.1			2.6
Other (3)	2.4			(0.6		)
Changes in operating assets and liabilities which provided cash:
Accounts receivable, accrued revenues, inventories and other	(102.8		)	(38.7		)
Accounts payable, accrued purchases and other (4)	71.0			35.1
Adjusted EBITDA before non-controlling interest	168.2			128.9
Non-controlling interest share of adjusted EBITDA	(25.1		)	(7.5		)
Transferred interest adjusted EBITDA (5)	(13.2		)	(7.8		)
Predecessor adjusted EBITDA	—			(82.8		)
Adjusted EBITDA, net to EnLink Midstream Partners, LP	$	129.9		$	30.8
Interest expense	(18.9		)	(4.8		)
Non-cash adjustment for mandatorily redeemable non-controlling interest	(2.6		)	—
Cash taxes and other	(0.8		)	—
Maintenance capital expenditures	(8.9		)	(1.5		)
Distributable cash flow	$	98.7		$	24.5


(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.


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


(5)	Represents recast E2 and recast EMH adjusted EBITDA.

Gross Operating Margin

We define gross operating margin, generally, as revenues less cost of purchased gas, NGLs, condensate and crude oil. 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 March 31,
	2015			2014
	(in millions)
Total gross operating margin	$	278.9		$	184.1

Add (deduct):
Operating expenses	(96.2		)	(46.2		)
General and administrative expenses	(41.9		)	(15.3		)
Depreciation and amortization	(90.0		)	(48.2		)
Operating income	$	50.8		$	74.4

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 purchased gas, NGLs, condensate and crude oil 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 three months ended March 31, 2015 may not be comparable to our financial results for the three months ended March 31, 2014 for the following reasons:

•

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


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

•

Subsequent to March 7, 2014, we owned a 75% interest in Midstream Holdings rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. We control Midstream Holdings through our ownership of its general partner. Our financial statements after March 7, 2014 consolidate all of Midstream Holdings’ financial results with ours in accordance with GAAP and ENLC’s 25% interest in Midstream Holdings is reflected as a non-controlling interest.


•	Our financial statements for the three months ended March 31, 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 March 31,
	2015			2014
	(in millions, except volumes)
Texas Segment
Revenues	$	211.3		$	384.2
Purchased gas and NGLs	(66.5		)	(257.7		)
Total gross operating margin	$	144.8		$	126.5
Louisiana Segment
Revenues	$	441.6		$	153.0
Purchased gas, NGLs and crude oil	(376.4		)	(140.5		)
Total gross operating margin	$	65.2		$	12.5
Oklahoma Segment
Revenues	$	43.9		$	174.4
Purchased gas and NGLs	(3.4		)	(133.8		)
Total gross operating margin	$	40.5		$	40.6
Crude and Condensate Segment
Revenues	$	263.7		$	20.1
Purchased crude oil and condensate	(235.5		)	(14.3		)
Total gross operating margin	$	28.2		$	5.8
Corporate
Revenues	$	(24.2	)	$	(8.7	)
Purchased gas and NGLs	24.4			7.4
Total gross operating margin	$	0.2		$	(1.3	)
Total
Revenues	$	936.3		$	723.0
Purchased gas, NGLs, condensate and crude oil	(657.4		)	(538.9		)
Total gross operating margin	$	278.9		$	184.1

Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)	2,751,000			2,952,200
Processing (MMBtu/d)	1,136,300			1,128,300
Louisiana (2)
Gathering and Transportation (MMBtu/d)	1,355,400			417,000
Processing (MMBtu/d)	434,400			642,700
NGL Fractionation (Gals/d)	5,632,000			3,291,900
Oklahoma (3)
Gathering and Transportation (MMBtu/d)	431,800			411,800
Processing (MMBtu/d)	356,500			425,000
Crude and Condensate (2)
Crude Oil Handling (Bbls/d)	66,300			11,900
Brine Disposal (Bbls/d)	3,600			4,600

__________________________________________________


(1)	Volumes include volumes per day based on the 90-day period for the three months ended March 31, 2015 and 90-day period for Midstream Holdings operations plus incremental volumes based on the 25-day period from March 7 to March 31, 2014 for the three months ended March 31, 2014 for Partnership’s legacy operations in Texas.


(2)	Volumes include volumes per day based on the 90-day period for the three months ended March 31, 2015 and 25-day period from March 7 to March 31, 2014 for the three months ended March 31, 2014 for the Partnership’s legacy operations. Midstream Holdings does not have any operations in Louisiana or Ohio.


(3)	Volumes include volumes per day based on the 90-day period for the three months ended March 31, 2015 and the 90-day period for Midstream Holdings operations for the three months ended March 31, 2014. The Partnership did not have any legacy operations in Oklahoma during 2014.

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Gross Operating Margin. Gross operating margin was $278.9 million for the three months ended March 31, 2015 as compared to $184.1 million for the three months ended March 31, 2014, an increase of $94.8 million, or 51.5% 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 and $17.2 million is attributable to the Chevron, LPC and Coronado acquisitions. This increase is partially offset by 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 $96.2 million for the three months ended March 31, 2015 as compared to $46.2 million for the three months ended March 31, 2014, an increase of $50.0 million, or 108.2%. Of this increase in operating expenses, $38.4 million is attributable legacy Partnership assets, $7.6 million is attributable to direct operating costs of the Chevron, LPC and Coronado acquisitions and $3.2 million is attributable to increase in Midstream Holdings' operating costs.

General and Administrative Expenses. General and administrative expenses were $41.9 million for the three months ended March 31, 2015 as compared to $15.3 million for the three months ended March 31, 2014, an increase of $26.6 million, or 173.9%. 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 $4.3 million is attributable to transaction costs related to Chevron, LPC and Coronado 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 $90.0 million for the three months ended March 31, 2015 as compared to $48.2 million for the three months ended March 31, 2014, an increase of $41.8 million, or 86.7%. Of this increase in depreciation and amortization expenses, $17.4 million is attributable to the legacy Partnership assets acquired in March 2014, $7.6 million is attributable to the Chevron, LPC and Coronado acquisitions and $19.1 million attributable is 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 $18.9 million for the three months ended March 31, 2015 as compared to $4.8 million for the three months ended March 31, 2014, an increase of $14.1 million, or 293.8%. Of the increase in interest expense, $16.2 million is attributable to the number of days debt was outstanding in 2014 compared to 2015. Interest expense for the three months ended March 31, 2015 includes interest expense for 90 days as compared to 25 days for the three months ended March 31, 2014. Further, average debt outstanding increased in 2015 as compared to 2014, which increased interest expense $1.2 million which was partially offset by $0.8 million due to a decrease in average interest rates. This increase was partially offset by an increase in non-cash interest income of $2.6 million attributable to the valuation of our mandatorily redeemable non-controlling interest. Net interest expense consists of the following (in millions):



	Three Months Ended March 31,
	2015			2014
Senior notes	$	20.3		$	5.3
Partnership credit facility	2.3			0.6
Capitalized interest	(1.3		)	(1.1		)
Amortization of debt issue cost, discount and premium	(0.2		)	(0.2		)
Mandatory redeemable non-controlling interest	(2.6		)	—
Other	0.4			0.2
Total	$	18.9		$	4.8

Income Tax Expense. Income tax expense was $1.2 million for the three months ended March 31, 2015 as compared to income tax expense of $19.6 million for the three months ended March 31, 2014, a decrease of $18.4 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.

Non-controlling interest. Non-controlling interest was $15.4 million for the three months ended March 31, 2015 as compared to $5.3 million for the three months ended March 31, 2014, an increase of 190.6%. Non-controlling interest for the three months ended March 31, 2014 includes ENLC's interest in Midstream Holdings subsequent to March 7, 2014.

Supplemental Information

As a supplement to the financial information included herein for the three months ended March 31, 2015, the Partnership is furnishing the following tables, which segregate the results of operations of Midstream Holdings from the Partnership's other operations. The tables below reflect the following for the three months ended March 31, 2015:


•	the Partnership's results of operations excluding the operations of Midstream Holdings;


•	the results of operations of 100% of Midstream Holdings on a stand-alone basis;


•	the elimination of the 25% of the net income of Midstream Holdings attributable to the non-controlling interest in Midstream Holdings held by ENLC;


•	the Partnership's results of operations on a consolidated basis.



	Three Months Ended March 31, 2015
	Partnership Excluding Midstream Holdings			Midstream Holdings			Eliminations			Partnership Consolidated
	(in millions)
Revenues:
Revenues	$	773.1		$	—		$	—		$	773.1
Revenues - affiliates	10.2			152.8			—			163.0
Gain on derivative activity	0.2			—			—			0.2
Total revenues	783.5			152.8			—			936.3
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil	647.0			10.4			—			657.4
Operating expenses	58.5			37.7			—			96.2
General and administrative	32.1			9.8			—			41.9
Depreciation and amortization	53.5			36.5			—			90.0
Total operating costs and expenses	791.1			94.4			—			885.5
Operating income (loss)	(7.6		)	58.4			—			50.8
Other income (expense):
Interest expense, net of interest income	(18.9		)	—			—			(18.9		)
Income from equity investments	0.4			3.3			—			3.7
Other income	0.6			—			—			0.6
Total other income (expense)	(17.9		)	3.3			—			(14.6		)
Income (loss) from continuing operations before non-controlling interest and income taxes	(25.5		)	61.7			—			36.2
Income tax provision	(0.6		)	(0.6		)	—			(1.2		)
Net income (loss)	(26.1		)	61.1			—			35.0
Net income attributable to the non-controlling interest	—			—			15.4			15.4
Net income (loss) attributable to EnLink Midstream Partners, LP	$	(26.1	)	$	61.1		$	(15.4	)	$	19.6

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, 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 March 31, 2015, we performed a qualitative analysis of goodwill noting no substantial decline in operations that would indicate an impairment. As of March 31, 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 $170.6 million for the three months ended March 31, 2015 compared to $122.5 million for the three months ended March 31, 2014. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):



	Three Months Ended March 31,
	2015		2014
Operating cash flows before working capital	$	138.8	$	118.9
Changes in working capital	$	31.8	$	3.6

The primary reason for the increase in operating cash flows before working capital of $19.9 million from 2014 to 2015 relates to an increase in gross operating margin from the acquired legacy Partnership assets and Midstream Holdings assets. The increase 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 $462.1 million for the three months ended March 31, 2015 and $124.5 million for the three months ended March 31, 2014. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):



	Three Months Ended March 31,
	2015			2014
Growth capital expenditures	$	142.5		$	94.0
Maintenance capital expenditures	11.7			3.8
Acquisition of businesses	312.0			29.3
Distribution from equity investment company in excess of earnings	(4.1		)	(2.6		)
Total	$	462.1		$	124.5

Cash Flows from Financing Activities. Net cash provided by financing activities was $316.1 million and $220.9 million for the three months ended March 31, 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):



	Three Months Ended March 31,
	2015			2014
Net borrowings (repayments) on Partnership credit facility	$	472.0		$	(377.0	)
Senior unsecured notes borrowings	—			1,190.0
Redemption of 2018 Notes	—			(562.9		)
Net borrowings on E2 credit facility	—			0.8
Net repayments under capital lease obligations	(1.0		)	(0.8		)
Debt refinancing costs	(1.8		)	(4.9		)
Proceeds from issuance of common units	2.2			—

Distributions to unitholders and our general partner also represent a primary use of cash in financing activities. Total cash distributions made during the three months ended March 31, 2015 was as follows (in millions):



	Three Months Ended March 31,
	2015
Common units	$	92.3
General partner interest (including incentive distribution rights)	7.6
Total	$	99.9

Midstream Holdings made distributions of $45.2 million to ENLC for the three months ended March 31, 2015 relating to ENLC's ownership interest in Midstream Holdings.

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 three months ended March 31, 2015 and 2014 were as follows (in millions):



	Three Months Ended March 31,
	2015			2014
Decrease in drafts payable	$	(12.7	)	$	(2.6	)

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 this damage. 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 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.

the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

Capital Requirements. During the three months ended March 31, 2015, capital investments were $142.5 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 $380.0 million related to identified growth projects. 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 2015 maintenance capital expenditures of approximately $38.4 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 March 31, 2015.

Total Contractual Cash Obligations. A summary of contractual cash obligations as of March 31, 2015 is as follows (in millions):



	Payments Due by Period
	Total		Remainder 2015		2016		2017		2018		2019		Thereafter
Long-term debt obligations	$	1,762.5	$	—	$	—	$	—	$	—	$	400.0	$	1,362.5
Credit facility	709.0		—		—		—		—		—		709.0
Other debt	0.3		0.1		0.1		0.1		—		—		—
Interest payable on fixed long-term debt obligations	1,403.8		79.6		81.3		81.3		81.3		75.9		1,004.4
Capital lease obligations	21.8		3.6		4.8		6.8		2.9		1.6		2.1
Operating lease obligations	114.9		6.4		10.0		6.7		11.6		9.0		71.2
Purchase obligations	190.5		190.5		—		—		—		—		—
Delivery contract obligation	76.2		13.5		17.9		17.9		17.9		9.0		—
Inactive easement commitment*	8.0		1.0		1.0		1.0		1.0		1.0		3.0
Uncertain tax position obligations	2.0		2.0		—		—		—		—		—
Total contractual obligations	$	4,289.0	$	4,585.7	$	115.1	$	113.8	$	114.7	$	496.5	$	3,152.2

__________________________________________________

* 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 March 31, 2015, the cash obligation for interest expense on the Partnership’s credit facility would be approximately $11.3 million per year or approximately $8.5 million for the remainder of 2015.

Indebtedness

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



	March 31, 2015		December 31, 2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2015 and December 31, 2014 was 1.6% and 1.9%, respectively	$	709.0	$	237.0
Senior unsecured notes (due 2019), net of discount of $0.5 million, which bear interest at the rate of 2.70%	399.5		399.5
Senior unsecured notes (due 2022), including a premium of $21.1 million at March 31, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%	183.7		184.4
Senior unsecured notes (due 2024), net of premium of $3.1 million at March 31, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%	553.1		553.2
Senior unsecured notes (due 2044), net of discount of $0.3 million, which bear interest at the rate of 5.60%	349.7		349.7
Senior unsecured notes (due 2045), net of discount of $1.6 million at March 31, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%	298.4		298.3
Other debt	0.3		0.4
Debt classified as long-term	$	2,493.7	$	2,022.5

Credit Facility. As of March 31, 2015, there were $2.9 million in outstanding letters of credit and $709.0 million of outstanding borrowings under the Partnership’s credit facility, leaving approximately $788.1 million 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, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. 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 three months ended March 31, 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

Table of Contents

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 90% of our processing margins are from fixed fee based contracts for the quarter ended March 31, 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 March 31, 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)

April 2015 - December 2016

Ethane

1,113

(MBbls)

$0.2781/gal

Index

(3.8

)

April 2015 - December 2016

Propane

1,170

(MBbls)

Index

$0.948/gal

20.0

April 2015 - March 2016

Normal Butane

117

(MBbls)

Index

$0.775/gal

0.7

April 2015 - March 2016

Natural Gasoline

101

(MBbls)

Index

$1.3157/gal

0.8

April 2015 - May 2015

Condensate

(MBbls)

Index

$48.44/Bbl

(0.1

)

April 2015 - March 2016

Natural Gas

2,631

(MMBtu/d)

$3.27/MMBtu*

Index

(0.2

)

17.4

__________________________________________________

*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 March 31, 2015, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $17.4 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 March 31, 2015.

Interest Rate Risk

We are exposed to interest rate risk on our variable rate credit facility. At March 31, 2015, we had $709.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change our annual interest expense by approximately $7.1 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, 2044 or 2045 as these obligations are fixed rates. The estimated fair value of our senior unsecured notes was approximately $1,861.9 million as of March 31, 2015, based on market prices of similar debt at March 31, 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 $161.7 million decrease in fair value of our senior unsecured notes at March 31, 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 (March 31, 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 March 31, 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 or results of operations.

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 February 17, 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 February 17, 2015, filed with the Commission on February 17, 2015).
2.2**	—	Contribution, Conveyance and Assumption Agreement, dated as of March 23, 2015, by and between EnLink Midstream Partners, LP and Devon Gas Services, L.P. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated March 23, 2015, filed with the Commission on March 23, 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	—	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).
3.8	—	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).
3.9	—	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).
10.1	—	Commitment Increase and Extension Agreement, dated as of February 5, 2015, by and among EnLink Midstream Partners, LP, the Lenders party thereto, and Bank of America, N.A., as an L/C Issuer, as Swing Line Lender, and as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated February 5, 2015, filed with the Commission on February 11, 2015).
10.2†	—	Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.3†	—	Form of Performance Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.4†		Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.5†		Form of Restricted Incentive Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
31.1*	—	Certification of the Principal Executive Officer.
31.2*	—	Certification of the Principal Financial Officer.
32.1*	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.



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

May 6, 2015