Exhibit 99.2 VEX and EMH Recast 10-Q

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.

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

We manage our operations by focusing on gross operating margin because our business is generally to 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:

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.

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.

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

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.

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

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

On May 27, 2015, the Partnership acquired the May Transferred Interests from Acacia, in the May EMH Drop Down in exchange for 36.6 million Class E Common Units in the Partnership. The Class E Common Units are substantially similar in all respects to the Partnership’s common units, except that they are only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units will convert into common units on a one-for-one basis on the first business day following the record date for distribution payments with respect to the distribution for the quarter ended June 30, 2015. After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings.

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.

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.

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.

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:

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.



Reconciliation of net income from continuing operations to adjusted EBITDA
	Three Months Ended March 31,
	2015			2014
	(in millions)
Net income from continuing operations	$	35.7		$	52.6
Interest expense	18.9			4.8
Depreciation and amortization	91.3			48.5
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			1.2
Adjusted EBITDA before non-controlling interest, Transferred Interests and Predecessor	170.2			128.0
Non-controlling interest share of adjusted EBITDA	(0.1		)	—
Transferred interest adjusted EBITDA (b)	(40.2		)	(14.4		)
Predecessor adjusted EBITDA	—			(82.8		)
Adjusted EBITDA, net to EnLink Midstream Partners, LP	$	129.9		$	30.8

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	$	171.8		$	121.8
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			(0.9		)
Changes in operating assets and liabilities which provided cash:
Accounts receivable, accrued revenues, inventories and other	(102.5		)	(38.7		)
Accounts payable, accrued purchases and other (4)	71.5			35.2
Adjusted EBITDA before non-controlling interest, Transferred Interests and Predecessor	170.2			128.0
Non-controlling interest share of adjusted EBITDA	(0.1		)	—
Transferred interest adjusted EBITDA (5)	(40.2		)	(14.4		)
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

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.



	Three Months Ended March 31,
	2015 (1)			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	$	267.9		$	20.1
Purchased crude oil and condensate	(235.5		)	(14.3		)
Total gross operating margin	$	32.4		$	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	$	940.5		$	723.0
Purchased gas, NGLs, condensate and crude oil	(657.4		)	(538.9		)
Total gross operating margin	$	283.1		$	184.1

Midstream Volumes:
Texas (2)
Gathering and Transportation (MMBtu/d)	2,751,000			2,952,200
Processing (MMBtu/d)	1,136,300			1,128,300
Louisiana (3)
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 (4)
Gathering and Transportation (MMBtu/d)	431,800			411,800
Processing (MMBtu/d)	356,500			425,000
Crude and Condensate (3)
Crude Oil Handling (Bbls/d)	89,900			11,900
Brine Disposal (Bbls/d)	3,600			4,600

__________________________________________________

Gross Operating Margin. Gross operating margin was $283.1 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 $99.0 million, or 53.8% 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, $17.2 million is attributable to the Chevron, LPC and Coronado acquisitions, and $4.2 million is attributable to the VEX pipeline which commenced operations in July 2014. 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 $98.4 million for the three months ended March 31, 2015 as compared to $46.8 million for the three months ended March 31, 2014, an increase of $51.6 million, or 110.3%. 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, $2.2 million is attributable to the VEX pipeline 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 $91.3 million for the three months ended March 31, 2015 as compared to $48.5 million for the three months ended March 31, 2014, an increase of $42.8 million, or 88.2%. 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, $19.1 million is attributable to new assets placed in service and $1.3 million is attributable to the VEX pipeline. These increases were 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 (1)
	Partnership Excluding Midstream Holdings			Midstream Holdings			Partnership Consolidated
	(in millions)
Revenues:
Revenues	$	773.1		$	—		$	773.1
Revenues - affiliates	10.2			157.0			167.2
Gain on derivative activity	0.2			—			0.2
Total revenues	783.5			157.0			940.5
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil	647.0			10.4			657.4
Operating expenses	58.5			39.9			98.4
General and administrative	32.1			9.8			41.9
Depreciation and amortization	53.5			37.8			91.3
Total operating costs and expenses	791.1			97.9			889.0
Operating income (loss)	(7.6		)	59.1			51.5
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		)	62.4			36.9
Income tax provision	(0.6		)	(0.6		)	(1.2		)
Net income (loss)	(26.1		)	61.8			35.7
Net income attributable to the non-controlling interest	0.1			—			0.1
Net income (loss) attributable to EnLink Midstream Partners, LP	$	(26.2	)	$	61.8		$	35.6

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.

The primary reason for the increase in operating cash flows before working capital of $22.5 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 Financing Activities. Net cash provided by financing activities was $321.9 million and $297.0 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			—

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):

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.

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.

Capital Requirements. During the three months ended March 31, 2015, capital investments were $149.4 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



	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	212.3		212.3		—		—		—		—		—
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 (1)	$	4,310.8	$	318.5	$	115.1	$	113.8	$	114.7	$	496.5	$	3,152.2

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.



	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.

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.

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.

This Current Report on Form 8-K ("Current Report") includes forward-looking statements within the meaning of federal securities laws. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such

statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Current Report, the risk factors set forth in Part II, “Item 1A. Risk Factors” of the Partnership's Quarterly Report on Form 10-Q for the three months ended March 31, 2015 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.



	Three Months Ended March 31,
	2015		2014
Operating cash flows before working capital	$	140.8	$	118.3
Changes in working capital	$	30.9	$	3.5



	Three Months Ended March 31,
	2015 (1)			2014 (1)
Growth capital expenditures	$	149.4		$	94.4
Maintenance capital expenditures	11.7			3.8
Acquisition of businesses (2)	312.0			104.3
Distribution from equity investment company in excess of earnings	(4.1		)	(2.6		)
Total	$	469.0		$	199.9


•	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.


(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.


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


•	Our financial statements for the 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.


•	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.


(1)	Financial information has been recast to include the financial position and results attributable to the VEX Interests.


(2)	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.


•	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;



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