Exhibit 99.2 E2 Recast

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included in Exhibit 99.3 to this Current Report on Form 8-K. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in Exhibit 99.3 to this Current Report on Form 8-K.

The historical financial statements included in this Exhibit 99.3 to this Current Report on Form 8-K 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% 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% 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 Exhibit 99.3 to this Current Report on Form 8-K. 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 (formerly known as Crosstex Energy Services, L.P.) (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, transmission, processing, fractionation, condensate stabilization, brine services and marketing to producers of natural gas, NGLs, crude oil and condensate. Our midstream energy asset network includes approximately 8,800 miles of pipelines, thirteen 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 100 trucks. We manage and report our activities primarily according to geography. We have five reportable segments: (1) Texas, which includes our activities in north Texas and the Permian Basin in west Texas; (2) Oklahoma, which includes our activities in Cana-Woodford and Arkoma-Woodford Shale areas; (3) Louisiana, which includes our pipelines, processing plants and NGL assets located in Louisiana; (4) Ohio River Valley ("ORV"), which includes our activities in the Utica and Marcellus Shales and our equity interests in E2 Energy Services, LLC, E2 Appalachian Compression, LLC and E2 Ohio Compression, LLC (collectively, “E2”); and (5) Corporate Segment, or Corporate, which includes our equity investments in Howard Energy Partners, or HEP, 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, or non-GAAP, financial measure and is explained in greater detail under “Non-GAAP Financial Measures” under Selected Financial Data in Exhibit 99.1 to this Current Report on Form 8-K.

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 same 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 its North Texas Pipeline and sell the gas into a different market area index. We realize a 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 December 31, 2014, the balance sheet reflects a liability of $80.7 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the 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 high liquids prices.

We generally gather or transport crude oil owned by others by rail, truck, pipeline and barge facilities for a fee, or we buy crude oil from a producer at a fixed discount to a market index, then transport and resell the crude oil at the same market index. We execute all purchases and sales substantially concurrently, thereby establishing the basis for the margin we will receive for each crude oil 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 liquids ("POL") 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 POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Under fixed-fee based contracts our gross operating margins are driven by throughput volume. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”) on February 20, 2015.

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, condensate or crude oil 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 a new class of limited partnership interests in the Partnership (the “Class B Units”). On February 17, 2015, Acacia Natural Gas Corp I, Inc. (“Acacia”) contributed a 25% interest in Midstream Holdings to us in exchange for 31.6 million of our Class D Common Units. See “Recent Growth Developments.”

The Partnership units held by Devon represent approximately 49% of the outstanding limited partner interests in the Partnership, with approximately 43% of the outstanding limited partner interests held by the Partnership’s public unitholders and approximately 7% of the outstanding limited partner interests, the approximate 1% general partner interest and the incentive distribution rights held indirectly by ENLC, as of December 31, 2014. The Class B Units were substantially similar in all respects to the Partnership’s common units representing limited partnership interests in the Partnership (“Common Units”), except that they were only entitled to a pro rata distribution for the fiscal quarter ended March 31, 2014. The Class B Units automatically converted into Common Units on a one-for-one basis on May 6, 2014.

Also on March 7, 2014, EnLink Midstream, Inc. ( “EMI”) and Devon consummated the transactions contemplated by the Merger Agreement, dated as of October 21, 2013 (the “Merger Agreement”), among EMI, Devon, ENLC, Acacia, formerly a wholly-owned subsidiary of Devon, 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.

Ohio River Valley Condensate Pipeline and Condensate Stabilization Facilities. In August 2014, we 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. As a component of the project, the Partnership has entered into a long-term, fee-based agreement under which Eclipse Resources will receive compression and stabilization services and has agreed to sell stabilized condensate to us.

The new-build stabilized condensate pipeline will connect to our existing 200-mile pipeline in the ORV, providing producer customers in the region access to premium market outlets through our barge facility on the Ohio River and rail terminal in Ohio. The pipeline, which is expected to be complete in the second half of 2015, is expected to have an initial capacity of approximately 50,000 Bbls/d.

We also expect to build and operate six natural gas compression and condensate stabilization facilities in Noble, Belmont, and Guernsey counties in Ohio. Upon completion, the facilities will have a combined capacity of approximately 560 MMcf/d of natural gas compression and approximately 41,500 Bbls/d of condensate stabilization. The first two compression and condensate stabilization facilities began operations during the fourth quarter of 2014 and the remaining four facilities are expected to be operational by the end of 2015.

Marathon Petroleum Joint Venture. We have entered into a series of agreements with a subsidiary of Marathon Petroleum Corporation to create a 50/50 joint venture named Ascension Pipeline Company, LLC. This joint venture will build a new 30-mile NGL pipeline connecting our existing Riverside fractionation and terminal complex to Marathon Petroleum's Garyville refinery located on the Mississippi River. The bolt-on project to our Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum. Under the arrangement, we will serve as the construction manager and operator of the pipeline project, which is expected to be operational in the first half of 2017.

Cajun-Sibon Phases I and II. In Louisiana, we have transformed our business that historically has been focused on processing offshore natural gas to a business that is now focused on NGLs with additional opportunities for growth from new onshore supplies of NGLs. The Louisiana petrochemical market historically has relied on liquids from offshore production; however, the decrease in offshore production and increase in onshore rich gas production have changed the market structure. Cajun-Sibon Phases I and II now bridge the gap between supply, which aggregates in the Mont Belvieu area, and demand, located in the Mississippi River corridor of Louisiana, thereby building a strategic NGL position in this region.

The pipeline expansion and the Eunice fractionation expansion under Phase I were completed and commenced operation in November 2013. Phase II of the Cajun-Sibon expansion was completed and commenced operation in September 2014, which increased the Cajun-Sibon pipeline capacity by an additional 50,000 Bbls/d to approximately 130,000 Bbls/d and added a new 100,000 Bbl/d fractionator at our Plaquemine gas processing complex. The throughput of the pipeline averaged 109,900 Bbls/d during the fourth quarter of 2014. Our fractionators in south Louisiana averaged approximately 98,300 Bbls/d during the fourth quarter of 2014.

We believe the Cajun-Sibon project represents a tremendous growth step by leveraging our Louisiana assets and also by creating a significant platform for continued growth of our NGL business. We believe this project, along with our existing assets, will provide a number of additional opportunities to grow this business, including expanding market optionality and connectivity, upgrading products, expanding rail imports, exporting NGLs and expanding fractionation and product storage capacity.

Bearkat Natural Gas Gathering and Processing System. In September 2014, we completed construction of a new natural gas processing complex and rich gas gathering pipeline system in the Permian Basin called Bearkat. The natural gas processing complex includes treating, processing and gas takeaway solutions for regional producers. The project, which is fully owned by us, is supported by a 10-year, fee-based contract.

Bearkat is strategically located near our existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant has an initial capacity of 60 MMcf/d, increasing our total operational processing capacity in the Permian Basin to approximately 115 MMcf/d. We also completed construction of a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan counties.

During 2014, we constructed a new 35-mile, 12-inch diameter high-pressure pipeline to provide gathering capacity for the Bearkat natural gas processing complex. The pipeline has an initial capacity of approximately 100 MMcf/d and provides gas takeaway solutions for constrained producer customers in Howard, Martin and Glasscock counties. The pipeline commenced operation in the fourth quarter of 2014.

West Texas Expansion. We are expanding our natural gas gathering and processing system in the Permian Basin by constructing a new natural gas processing plant and expanding our rich gas gathering system. The new 120 MMcf/d gas processing plant will be strategically located on the north end of our existing midstream assets and will offer additional gas processing capabilities to producer customers in the region, including Devon. Due to the impact from the current commodity environment and a shift in producers' drilling expectations, we are delaying construction on the processing plant until late 2015. Upon completion, our total operated processing capacity in the region will be approximately 240 MMcf/d.

As a part of the expansion, we have signed a long-term, fee-based agreement with Devon to provide gathering and processing services for over 18,000 acres under development in Martin County. We constructed multiple low pressure gathering pipelines and a new 23-mile, 12-inch high pressure gathering pipeline that will tie into the previously announced Bearkat natural gas gathering system. The new pipelines commenced operation in January 2015.

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 (the “EMH Drop Down”). As consideration for the Transferred Interest, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia. The Partnership’s 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 Partnership’s Class D Common Units will automatically convert into the Partnership’s 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 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.

E2 Drop Down. On October 22, 2014, the Partnership acquired from EMI, a wholly-owned subsidiary of ENLC, 100% of the Class A Units and 50% of the Class B Units (collectively, the “E2 Appalachian Units”) in E2 Appalachian Compression, LLC (“E2 Appalachian”), and 93.7% of the Class A Units (the “Energy Services Units” and, together with the E2 Appalachian Units, the “Purchased Units”) in E2 Energy Services, LLC (“Energy Services”). The total consideration paid by the Partnership

to EMI for the Purchased Units included (i) $13.0 million in cash for the Energy Services Units and (ii) $150.0 million in cash and 1,016,322 common units representing limited partner interests in the Partnership for the E2 Appalachian Units. The remaining 50% of the Class B Units in E2 Appalachian are owned by members of the E2 Appalachian management team and are designed to provide such management team members with equity incentives.

E2’s assets include five condensate stabilization and natural gas compression stations with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression located in the ORV. Currently, three of the five stations are in service and commercial start-up of the two remaining stations is expected in the first half of 2015. The assets are supported by a long-term, fee-based contract with Antero Resources.

Coronado Midstream. On February 1, 2015, the Partnership entered into an agreement with Reliance Midstream, LLC, a Texas limited liability company (“Reliance”), Windsor Midstream LLC, a Delaware limited liability company (“Windsor”), Wallace Family Partnership, LP, a Texas limited partnership (“Wallace”), and Ted Collins, Jr., an individual residing in Midland, Texas (“Collins” and, collectively with Reliance, Windsor and Wallace, the “Sellers,” and each, a “Seller”), and Reliance in its capacity as representative of the Sellers, to acquire 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. 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.

LPC Crude Oil Marketing ("LPC"). On January 31, 2015, the Partnership, through one of its wholly owned subsidiaries, acquired 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 operation 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.

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 representing limited partner interests 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. Through December 2014, the Partnership sold an aggregate of 0.3 million common units under the BMO EDA, generating proceeds of approximately $7.8 million (net of approximately $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million. Through December 31, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating proceeds of approximately $71.9 million (net of approximately $0.7 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes.



	For years ended December 31,
	2014			2013			2012
	(in millions, except volumes)
Texas Segment
Revenues	$	1,067.2		$	1,549.1		$	1,357.2
Purchased gas and NGLs	(490.9		)	(1,130.4		)	(983.3		)
Total gross operating margin	$	576.3		$	418.7		$	373.9
Louisiana Segment
Revenues	$	1,925.5		$	—		$	—
Purchased gas, NGLs and crude oil	(1,754.2		)	—			—
Total gross operating margin	$	171.3		$	—		$	—
Oklahoma Segment
Revenues	$	318.8		$	746.8		$	550.6
Purchased gas and NGLs	(142.5		)	(605.9		)	(444.8		)
Total gross operating margin	$	176.3		$	140.9		$	105.8
Ohio River Valley Segment
Revenues	$	261.3		$	—		$	—
Purchased crude oil and condensate	(201.4		)	—			—
Total gross operating margin	$	59.9		$	—		$	—
Corporate
Revenues	$	(72.4	)	$	—		$	—
Purchased gas, NGLs and crude oil	94.5			—			—
Total gross operating margin	$	22.1		$	—		$	—
Total
Revenues	$	3,500.4		$	2,295.9		$	1,907.8
Purchased gas, NGLs, crude oil and condensate	(2,494.5		)	(1,736.3		)	(1,428.1		)
Total gross operating margin	$	1,005.9		$	559.6		$	479.7
Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)	2,958,000			2,102,000			2,127,000
Processing (MMBtu/d)	1,146,000			811,000			753,000
Louisiana (2)
Gathering and Transportation (MMBtu/d)	615,200			—			—
Processing (MMBtu/d)	547,000			—			—
NGL Fractionation (Gals/d) (4)	3,804,300			—			—
Oklahoma (3)
Gathering and Transportation (MMBtu/d)	471,000			390,000			351,000
Processing (MMBtu/d)	442,000			400,000			340,000
ORV (2)
Crude Oil Handling (Bbls/d)	16,300			—			—
Brine Disposal (Bbls/d)	4,700			—			—

Gross Operating Margin. Gross operating margin was $1,005.9 million for the year ended December 31, 2014 compared to $559.6 million for the year ended December 31, 2013, an increase of $446.3 million, or 79.8%. Of this increase in gross operating margin, $386.8 million is attributable to the legacy Partnership assets associated with the business combination effective on March 7, 2014. Approximately $59.5 million of the increase in gross operating margin is related to an increase in gross operating margin at Midstream Holdings as a result of the new fixed-fee arrangements with Devon entered into in connection with the business combination.

Operating Expenses. Operating expenses were $278.2 million for the year ended December 31, 2014 compared to $156.2 million for the year ended December 31, 2013, an increase of $122.0 million, or 78.1%. Of this increase in operating expenses, $145.6 million is attributable to the legacy Partnership assets, partially offset by a decrease in Midstream Holdings’ operating expenses of $23.6 million due to both lower personnel and contract labor expense and a decrease in compressor maintenance expense.

General and Administrative Expenses. General and administrative expenses were $94.5 million for the year ended December 31, 2014 compared to $45.1 million for the year ended December 31, 2013, an increase of $49.4 million, or 109.5%. General and administrative expenses for the year ended December 31, 2014 reflect expenses associated with the new combined operations of the legacy Partnership and Midstream Holdings since March 7, 2014, including $3.3 million for transition service costs from Devon, together with general and administrative expenses of Midstream Holdings prior to March 7, 2014. General and administrative expenses for the year ended December 31, 2013 reflect expenses for Midstream Holdings which primarily consisted of costs allocated by Devon for shared general and administrative services.

Depreciation and Amortization. Depreciation and amortization expenses were $280.3 million for the year ended December 31, 2014 compared to $187.0 million for the year ended December 31, 2013, an increase of $93.3 million, or 49.9%. The increase in depreciation and amortization expenses result from an increase in depreciation expense of $137.9 million related to the legacy Partnership assets acquired in March 2014 together with additional depreciation for net asset additions during 2014. The increase was partially offset by a decrease of $44.6 million in depreciation and amortization expenses related to Midstream Holdings primarily due to the change in depreciation methodology from the units-of-production method to the straight-line method which accounted for $29.4 million of such decrease. The remaining $5.6 million decrease was related to a change in the annual units-of-production rate partially offset by a $1.7 million increase related to assets placed in service during 2013.

Income Tax Expense. Income tax expense was $22.0 million for the year ended December 31, 2014 as compared to income tax expense of $67.0 million for the year ended December 31, 2013, a decrease of $45.0 million. The decrease in income tax expense primarily relates to a reduction in our taxable income as compared to the Predecessor, which was a taxable entity prior to the business combination.

Net Income from Discontinued Operations. Net income from discontinued operations was $1.0 million for the year ended December 31, 2014 as compared to a net loss of $3.6 million for the year ended December 31, 2013, an increase of $4.6 million. The increase is due to Midstream Holdings’ discontinued operations for the year ended December 31, 2013 which included assets that were sold during 2013, while year ended December 31, 2014 includes Predecessor assets that were not contributed to Midstream Holdings as part of the business combination.

Gross Operating Margin. Gross operating margin was $559.6 million for the year ended December 31, 2013 compared to $479.7 million for the year ended December 31, 2012, an increase of $79.9 million, or 16.7%. Higher gathering, processing and transportation volumes were responsible for an increase in gross operating margin of $32.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Higher volumes were primarily the result of NGL production increasing 25%, resulting in $34.1 million of higher gross operating margin. The increase in NGL production was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and unplanned downtime impacting Midstream Holdings’ Bridgeport processing facility in 2012. The increase in NGL production was partially offset by slightly lower throughput volumes, primarily on the Predecessor’s East Johnson and Northridge gathering systems.

Changes in pricing led to an increase in gross operating margin of $48.4 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Natural gas pipeline fees increased 15%, which resulted in $44.2 million of additional revenues. Additionally, higher residue natural gas prices contributed an additional $32.4 million to gross operating margin. These increases were partially offset by lower margins of $28.2 million primarily due to NGL price declines.

Depreciation and Amortization. Depreciation and amortization expenses were $187.0 million for the year ended December 31, 2013 compared to $145.4 million for the year ended December 31, 2012, an increase of $41.6 million, or 28.6%. The increase primarily resulted from higher capitalized costs on the Cana system. Devon and other producers have continued to grow natural gas production in the Cana-Woodford Shale. As a result, we have increased our throughput capacity by expanding our pipeline and gathering systems and our Cana processing facility.

Income Tax Expense. Income tax expense was $67.0 million for the year ended December 31, 2013 as compared to income tax expense of $46.2 million for the year ended December 31, 2012, an increase of $20.8 million. This increase primarily relates to an increase in taxable income related to the Predecessor. During 2013 and 2012, effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.



	Year Ended December 31, 2014
	Predecessor			Partnership Excluding Midstream Holdings			Midstream Holdings			Eliminations (1)			Partnership Consolidated
	(in millions)
Revenues:
Revenues	$	47.3		$	2,365.4		$	—		$	—		$	2,412.7
Revenues - affiliates	436.4			115.3			513.9			—			1,065.6
Gain on derivatives	—			22.1			—			—			22.1
Total revenues	483.7			2,502.8			513.9			—			3,500.4
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil	368.5			2,116.0			10.0			—			2,494.5
Operating expenses	23.7			145.7			108.8			—			278.2
General and administrative	10.9			52.9			30.7			—			94.5
Depreciation and amortization	28.9			138.0			113.4			—			280.3
Gain on sale of property	—			(0.1		)	—			—			(0.1		)
Gain on litigation settlement	—			(6.1		)	—			—			(6.1		)
Total operating costs and expenses	432.0			2,446.4			262.9			—			3,141.3
Operating income	51.7			56.4			251.0			—			359.1
Other income (expense):
Interest expense, net of interest income	—			(47.4		)	—			—			(47.4		)
Income from equity investments	2.8			1.8			14.3			—			18.9
Gain on extinguishment of debt	—			3.2			—			—			3.2
Other expense	(0.5		)	0.2			(0.2		)	—			(0.5		)
Total other income (expense)	2.3			(42.2		)	14.1			—			(25.8		)
Income from continuing operations before non-controlling interest and income taxes	54.0			14.2			265.1			—			333.3
Income tax provision	(19.5		)	(0.5		)	(2.0		)	—			(22.0		)
Net income from continuing operations	34.5			13.7			263.1			—			311.3
Discontinued operations:
Income from discontinued operations, net of tax	1.0			—			—			—			1.0
Discontinued operations, net of tax	1.0			—			—			—			1.0
Net income	35.5			13.7			263.1			—			312.3
Net income attributable to the non-controlling interest	—			—			—			65.5			65.5
Net income attributable to EnLink Midstream Partners, LP	$	35.5		$	13.7		$	263.1		$	(65.5	)	$	246.8

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.

Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services at the time the natural gas, NGL, condensate or crude oil is delivered or at the time the service is performed. We generally accrue one month of sales and the related gas, NGL, condensate or crude oil purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

We utilize extensive estimation procedures to determine the sales and cost of gas, NGL, condensate or crude oil purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. We use actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as “actualization”. Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month's accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. We believe that our accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, NGLs, crude oil and condensate. We also manage our price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas, NGL and crude oil prices.

We use derivatives to hedge against changes in cash flows related to product prices, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. We manage our price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas prices. However, we are subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives and we use mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized currently in earnings as gain on derivatives.

Impairment of Long-Lived Assets. In accordance with FASB ASC 360-10-05, we evaluate long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, NGLs and crude oil, volume of gas, NGLs and crude oil available to the asset, markets available to the asset, operating expenses, and future natural gas, NGL product and crude oil prices. The amount of availability of gas, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas and crude oil prices. Projections of gas, NGL and crude oil volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31st, and also whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, 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 carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

At October 31, 2014, the date of our last impairment test, the fair values of our Texas, Louisiana, Oklahoma and ORV reporting units exceeded their related carrying values. The fair value of our Texas, Oklahoma and ORV reporting units substantially exceeded carrying value. However, the fair value of our Louisiana reporting unit is not substantially in excess of its carrying value. As of October 31, 2014, the fair value of our Louisiana reporting unit exceeded its carrying value by approximately 14 percent. As of December 31, 2014, we had $273.1 million of goodwill allocated to the Louisiana reporting unit.

Depreciation Expense and Cost Capitalization. Our assets consist primarily of natural gas, NGL, condensate and crude oil gathering pipelines, processing plants, condensate stabilization facilities, transmission pipelines and trucks. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, Midstream Holdings is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Partnership changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Partnership’s legacy assets. In accordance with FASB ASC 250, the Partnership determined that the change in depreciation method is a change in accounting estimate, and accordingly, the straight-line method will be applied on a prospective basis. This change is considered preferable because the straight-line method more accurately reflects the pattern of usage and the expected benefits of such assets.

Certain assets such as land, NGL line pack, natural gas line pack and crude oil line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we may review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

We are subject to significant risks due to fluctuation in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. Processing margin and POL contracts are two types of contracts under which we process gas and are exposed to commodity price risk. For the year ended December 31, 2014, approximately 1.7% of our processed gas arrangements, based on gross operating margin, were processed under POL contracts. A portion of the volume of inlet gas at our south Louisiana and north Texas processing plants is settled under POL agreements. Under these contracts we receive a fee in the form of a percentage of the liquids recovered and the producer bears all the costs of the natural gas volumes lost (“shrink”). Accordingly, our revenues under these contracts are directly impacted by the market price of NGLs.

We also realize processing gross operating margin under margin contracts and spot purchases. For the year ended December 31, 2014, approximately 2.1% of our processed gas arrangements, based on gross operating margin, was processed under margin contracts and spot purchases. We have a number of margin contracts on our Plaquemine and Pelican processing plants. 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 shrink and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR.

In the past, the prices of oil, natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2014 ranged from a high of $107.26 per Bbl in June 2014 to a low of $53.27 per Bbl in December 2014. Weighted average NGL prices in 2014 (based on the Oil Price Information Service ("OPIS") Napoleonville daily average spot liquids prices) ranged from a high of $1.22 per gallon in February 2014 to a low of $0.45 per gallon in December 2014. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2014 ranged from a high of $7.94 per MMBtu in March 2014 to a low of $2.75 per MMBtu in December 2014.

Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, NGLs, crude oil and condensate we gather and process. The volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. For a discussion of our risk management activities, please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014.

The primary reason for the increase in cash flows before working capital of $249.8 million from 2013 to 2014 relates to an increase in gross operating margin from the acquired legacy Partnership assets and Midstream Holdings assets. The decrease in working capital for 2014 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 $1,104.5 million, $243.2 million and $352.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Our primary use of cash related to investing activities for the years ended December 31, 2014, 2013 and 2012 was acquisition costs and capital expenditures, net of accrued amounts, and an investment in equity investments as follows (in millions):



	Years Ended December 31,
	2014			2013			2012
Growth capital expenditures	$	726.5		$	180.8		$	249.5
Maintenance capital expenditures	37.1			63.5			87.7
Acquisition of business and asset purchases	346.2			—			—
Proceeds from sale of property	(0.1		)	—			—
Investment in equity investments	5.7			—			17.1
Distribution from equity investment company in excess of earnings	(10.9		)	(1.1		)	(1.9		)
Total	$	1,104.5		$	243.2		$	352.4

Distributions to unitholders including our general partner, and distributions to ENLC relating to its ownership interest in Midstream Holdings represent primary uses of cash in financing activities. Also, Midstream Holdings made distributions of $159.5 million to ENLC for the year ended December 31, 2014 relating to ENLC's 50% ownership interest in Midstream Holdings during such period. Total unitholder cash distributions made during the years ended December 31, 2014 were as follows (in millions):

Prior to the business combination, Midstream Holdings’ continuing operations had no separate cash accounts. The owner contributions and distributions represent the net amount of all transactions that were settled with adjustments to equity. Midstream Holdings had distributions of $21.3 million to Devon for the year ended December 31, 2014 (relating to the period from January 1, 2014 to March 6, 2014), distributions to Devon of $151.2 million for the year ended December 31, 2013 and contributions from Devon of $87.8 million for the year ended December 31, 2012.

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 revolving credit facility. We borrow money under our credit facility to fund checks as they are presented. As of December 31, 2014, we had approximately $749.1 million of available borrowing capacity under this facility, although our actual borrowing capacity is limited by our financial covenant. Changes in drafts payable for 2014 were as follows (in millions):



	Years Ended December 31,
	2014		2013		2012
Increase (decrease) in drafts payable	$	10.2	$	—	$	(1.6	)

Capital Requirements. Our 2015 capital budget includes around $500.0 million of identified growth projects, including capitalized interest. Our primary capital projects for 2015 include the construction of our ORV condensate pipeline, Bearkat plant facilities and West Texas expansion project. During 2014, we invested in several capital projects which primarily included the expansion of the Cajun-Sibon NGL Pipeline and the construction of the Bearkat facilities. See “Recent Growth Developments” for further details.

We expect to fund our 2015 maintenance capital expenditures of around $50.0 million from operating cash flows. We expect to fund the growth capital expenditures from the proceeds of borrowings under our bank credit facility discussed below and proceeds from other debt and equity sources. 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.



	Payments Due by Period
	Total		2015		2016		2017		2018		2019		Thereafter
Long-term debt obligations	$	1,762.5	$	—	$	—	$	—	$	—	$	400.0	$	1,362.5
Bank credit facility	237.0		—		—		—		—		237.0		—
Other Debt	0.4		0.2		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	23.0		4.8		4.8		6.8		2.9		1.6		2.1
Operating lease obligations	119.1		11.6		9.2		6.6		11.5		9.0		71.2
Purchase obligations	86.8		86.8		—		—		—		—		—
Delivery contract obligation	80.7		17.9		17.9		17.9		17.9		9.1		—
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	$	3,723.3	$	203.9	$	114.3	$	113.7	$	114.6	$	733.6	$	2,443.2



	2014
Bank credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at December 31, 2014 was 1.9%	$	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
Senior unsecured notes (due 2022), including a premium of $21.9 million, which bear interest at the rate of 7.125%	184.4
Senior unsecured notes (due 2024), including a premium of $3.2 million, which bear interest at the rate of 4.40%	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
Senior unsecured notes (due 2045), net of discount of $1.7 million, which bear interest at the rate of 5.05%	298.3
Other debt	0.4
Debt classified as long-term	$	2,022.5

Credit Facility. On February 20, 2014, the Partnership entered into a new $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 commitments under the Partnership credit facility were increased to $1.5 billion and the maturity date was extended by a year. The Partnership credit facility will mature on the sixth anniversary of the initial funding date, which was March 7, 2014, unless the Partnership requests, and the requisite lenders agree, to extend it pursuant to its terms. 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 increase 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 December 31, 2014, there were $13.9 million in outstanding letters of credit and $237.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $749.1 million available for future borrowing based on the borrowing capacity of $1.0 billion.



Pricing Levels	Debt Ratings	Applicable Rate Commitment Fee	EuroDollar Rate/Letter of Credit	Base Rate +
1	A-/A3 or better	0.100%	1.000%	—%
2	BBB+/Baa1	0.125%	1.125%	0.125%
3	BBB/Baa2	0.175%	1.250%	0.250%
4	BBB-/Baa3	0.225%	1.500%	0.500%
5	BB+/Ba1	0.275%	1.625%	0.625%
6	BB/Ba2 or worse	0.350%	1.750%	0.750%

Senior Unsecured Notes. On March 7, 2014, the Partnership recorded, in the business combination, $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “2018 Notes”) due on February 15, 2018. As a result of the business combination, the 2018 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $761.3 million, including a premium of $36.3 million, as of March 7, 2014.

in accordance with acquisition accounting at an amount of $226.0 million, including a premium of $29.5 million. On July 20, 2014, the Partnership redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million, including accrued interest. On September 20, 2014, the Partnership redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2022 Notes of $2.4 million for the year ended December 31, 2014.

On March 12, 2014, the Partnership commenced a tender offer to purchase any and all of the outstanding 2018 Notes. Approximately $536.1 million, or approximately 74%, of the 2018 Notes were validly tendered and on March 19, 2014, the Partnership made a payment of approximately $567.4 million for all such tendered 2018 Notes. Also on March 19, 2014, the Partnership delivered a notice of redemption for any and all outstanding 2018 Notes. All remaining outstanding 2018 Notes were redeemed on April 18, 2014 for $200.2 million, including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2018 Notes of $0.7 million for the year ended December 31, 2014.

On March 19, 2014, the Partnership issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of its 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “Initial 2024 Notes”) and $350.0 million aggregate principal amount of its 5.600% senior notes due 2044 (the “2044 Notes”), at prices to the public of 99.850%, 99.830% and 99.925%, respectively, of their face value. The 2019 Notes mature on April 1, 2019, the 2024 Notes mature on April 1, 2024 and the 2044 Notes mature on April 1, 2044. The interest payments on the 2019 Notes, 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October.

On November 12, 2014, the Partnership issued $400 million aggregate principal amount of unsecured senior notes, consisting of $100.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “Additional 2024 Notes” and together with the Initial 2024 Notes, the “2024 Notes”) and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes,” and, together with the 2018 Notes, 2019 Notes, 2022 Notes, 2024 Notes and 2044 Notes, the “Senior Notes”), at prices to the public of 104.007% and 99.452%, respectively, of their face value. The Additional 2024 Notes and the Initial 2024 Notes are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and the interest payments on the 2045 Notes are due semi-annually in arrears in April and October.

Prior to June 1, 2017, the Partnership may redeem all or part of the remaining 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date. On or after June 1, 2017, the Partnership may redeem all or a part of the remaining 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2019 Notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the 2019 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2024 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 25 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to 100% of the principal amount of the 2024 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2043, the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2044 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2044 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or

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

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders.

Inflation in the United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry's labor and material costs remained relatively unchanged in 2012, 2013 and 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see “Item 1. Business—Environmental Matters” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014.

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 that 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. The court’s ruling is subject to appeal. The Partnership intends to vigorously defend the case. 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.

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 related to the sinkhole from responsible parties. We have sued 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 Company, LLC, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as 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.

This Current Report on Form 8-K (“Current Report”) contains forward-looking statements within the meaning of federal securities laws that are based on information currently available to management as well as management's assumptions and beliefs. All statements, other than statements of historical fact, included in this Current Report constitute forward-looking statements, including but not limited to statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate” and “expect” and similar expressions. 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 the specific uncertainties discussed elsewhere in this Current Report, the risk factors set forth in “Item 1A. Risk Factors” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014 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.



	Years Ended December 31,
	2014			2013			2012
Operating cash flows before working capital	$	588.0		$	338.2		$	229.8
Changes in working capital	(110.2		)	(7.9		)	(20.1		)
Total	$	477.8		$	330.3		$	209.7



	Year Ended December 31,
	2014
Net repayments on bank credit facility	$	(140.0	)
Senior unsecured notes borrowings	1,600.7
Redemption of 2018 notes	(760.3		)
Partial redemption of 2022 notes	(36.4		)
Net repayments on E2 credit facility	(13.8		)
Net repayments under capital lease obligations	(3.0		)
Debt refinancing costs	(18.5		)
Proceeds from issuance of Partnership units	412.0



	Year ended December 31,
	2014 (1)
Common units	$	222.7
General partner interest (including incentive distribution rights)	17.1
Total	$	239.8


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


•	providing crude oil and condensate transportation and terminal services;


•	Bridgeline System: approximately 990 miles of natural gas pipelines in southern Louisiana with a total system capacity of approximately 900 MMcf/d;


•	Sabine Pipeline: approximately 130 miles of natural gas pipelines in Texas and southern Louisiana with a total capacity of approximately 300 MMcf/d;


•	Chandeleur System: approximately 215 miles of offshore Mississippi and Alabama pipelines with a total capacity of approximately 300 MMcf/d;


•	Storage Assets: three caverns located in southern Louisiana with a combined working capacity of approximately 11 Bcf of natural gas, including two near Sorrento, LA with a capacity of approximately 4.0 Bcf and one inactive cavern near Napoleonville, LA with approximately 7.0 Bcf of capacity; and


•	Henry Hub: ownership and management of the title tracking services offered at the Henry Hub, the delivery location for the New York Mercantile Exchange (the “NYMEX”) natural gas futures contracts. Henry Hub is connected to 13 major interstate and intrastate natural gas pipeline and storage systems.


•	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 prior to giving effect to the business combination.


•	Our financial statements for the year ended December 31, 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 will not be subject to U.S. federal income tax or certain state income taxes in the future.


(1)	Volumes include volumes per day based on 365 day period for the years ended December 31, 2014, 2013 and 2012 for Midstream Holdings operations. Volumes include volumes per day based on the 300 day period from March 7 to December 31, 2014 for the year ended December 31, 2014 for the Partnership’s legacy operations in Texas.


(3)	Volumes include volumes per day based 365 day period for the years ended December 31, 2014, 2013 and 2012 respectively, for Midstream Holdings operations. The Partnership did not have any legacy operations in Oklahoma.



	Year Ended December 31,
	2014
Senior notes	$	55.6
Bank credit facility	5.8
Capitalized interest	(11.5		)
Amortization of debt issue costs and net discount (premium)	(1.2		)
Cash settlements on interest rate swap	(3.6		)
Other	2.3
Total	$	47.4


•	the Predecessor's results of operations for the period January 1, 2014 through March 6, 2014;


•	the Partnership's results of operations excluding the operations of Midstream Holdings for the period March 7, 2014 through December 31, 2014;


•	the results of operations of 100% of Midstream Holdings on a stand-alone basis for the period March 7, 2014 through December 31, 2014;


•	the elimination of the 25% of the net income of Midstream Holdings attributable to the non-controlling interest in Midstream Holdings held by ENLC for the period March 7, 2014 through December 31, 2014; and


(1)	Information has been recast to include results attributable to the 25% limited partner interest in Midstream Holdings (the “Transferred Interest”) acquired by the Partnership from Acacia.


•	changes in general economic conditions in regions in which our markets are located;


•	the availability and prices of natural gas, NGLs, crude oil and condensate supply;


•	the risks that natural gas, NGLs, crude oil and condensate exploration and production activities will not occur or be successful;


•	our dependence on certain significant customers, producers and transporters of natural gas, NGLs, crude oil and condensate; and


•	competition from other midstream companies, including major energy companies.


(1)	Excludes distribution declared for the fourth quarter of 2014, which was paid on February 12, 2015.


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