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•	17,431,152 common units representing an aggregate 7% limited partner interest in the Partnership as of December 31, 2014;

•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest as of December 31, 2014 and all of the incentive distribution rights in the Partnership; and

•	50.0% limited partner interest in Midstream Holdings as of December 31, 2014 and 25% limited partner interest in Midstream Holdings as of February 17, 2015.

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•	federal income taxes, which we are required to pay because we are taxed as a corporation;

•	the expenses of being a public company;

•	other general and administrative expenses;

•	capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s then-current general partner interest, to the extent the board of directors of the general partner exercises its option to do so; and

•	cash reserves our board of directors believes are prudent to maintain.

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•	Texas. The Partnership's Texas assets consist of transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.2 Bcf/d and gathering systems with total capacity of approximately 2.8 Bcf/d.

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•	Oklahoma. Midstream Holdings' Oklahoma assets consist of processing facilities with a total processing capacity of approximately 550 MMcf/d and gathering systems with total capacity of approximately 605 MMcf/d.

•	Louisiana. The Partnership’s Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.7 Bcf/d and gathering systems with total capacity of approximately 510 MMcf/d.

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Ohio River Valley. The Partnership’s Ohio River Valley (“ORV”) operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot operation crude oil and condensate rail loading terminal on the Ohio Central Railroad network and approximately 200 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include 500,000 barrels of above ground storage and a trucking fleet of approximately 100 vehicles comprised of both semi and straight trucks. The Partnership has eight existing brine disposal wells with an injection capacity of approximately 5,000 Bbls/d. Additionally, the Partnership's ORV operations include five condensate stabilization and natural gas compression stations, including two stations under construction, with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression.

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Organic Growth: pursue opportunities around the Midstream Entities’ existing footprint. The Midstream Entities expect to grow certain of their systems organically over time by meeting Devon’s and their other customers’ midstream service needs that result from their drilling activity in the Midstream Entities’ areas of operation. The Midstream Entities continually evaluate whether to pursue economically attractive organic expansion opportunities in existing or new areas of operation that allow the Midstream Entities to leverage their existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand for the Midstream Entities’ services.

•	Growing with Devon: The Midstream Entities expect their relationship with Devon will continue to provide them with significant business opportunities. Devon is a leading North American E&P company with a focus on five core growth areas: Eagle Ford, Permian Basin, Anadarko Basin, Canadian oil sands and the Barnett Shale.

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Dropdowns: maximize opportunities provided by Devon’s sponsorship and assets held by the Company. The Midstream Entities plan to execute their growth in part through pursuing accretive dropdown opportunities from Devon and the Company. On February 17, 2015, the Partnership purchased a 25% interest in Midstream Holdings from us, increasing its ownership in Midstream Holdings to 75%, and we expect to give the Partnership the opportunity over time to purchase the remaining interest in Midstream Holdings held by us. ENLC and Devon are parties to a first offer agreement pursuant to which ENLC has a right of first offer with respect to Devon’s 50% interest in the Access Pipeline (the “First Offer Agreement”). The Partnership is party to a preferential rights agreement with us and our wholly-owned subsidiary pursuant to which we granted the Partnership a right of first refusal, for a period of 10 years, with respect to Devon’s 50% interest in the Access Pipeline transportation system, to the extent in the future we obtain such interest pursuant to a first offer agreement between Devon and us. In addition, if ENLC has the opportunity to exercise its right of first offer for Devon’s interest in the Access Pipeline pursuant to the First Offer Agreement, but determines not to exercise such right, ENLC is required to assign such right to the Midstream Entities. Though there is no contractual obligation, the Midstream Entities anticipate being given the opportunity to purchase the Victoria Express Pipeline from Devon in the future. The Midstream Entities also believe there will continue to be significant opportunities as Devon continues to develop its oil and gas production. However, the Midstream Entities cannot be certain that these opportunities will be made available to them, or that they will choose to pursue any such opportunity.

•	Acquisitions: pursue strategic and accretive acquisitions. The Midstream Entities pursue strategic and accretive acquisition opportunities within the midstream energy industry, both in new and existing lines of business, and geographic areas of operation.

•	Strong Balance Sheet: maintain an investment grade quality financial profile. The Midstream Entities intend to maintain appropriate leverage and other key financial metrics in line with other partnerships in the Midstream Entities’

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Devon’s sponsorship. The Midstream Entities expect their relationship with Devon will continue to provide them with significant business opportunities. Devon is one of the largest independent oil and gas producers in North America. Devon has a significant interest in promoting the success of the Midstream Entities’ business, due to its approximate 70% ownership interest in us and approximate 49% ownership interest in the Partnership.

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Strategically-located assets. The Midstream Entities' assets are strategically located in strategic producing regions with the potential for increasing throughput volume and cash flow generation. The Midstream Entities' assets are in areas consistent with Devon's strategic focus. The Midstream Entities' asset portfolio includes gathering, transmission, fractionation, processing and stabilization systems that are located in areas in which producer activity is focused on crude oil, condensate and NGLs as well as natural gas. The Midstream Entities have developed or are in the process of developing platforms in these areas through organic development and acquisitions.

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Stable cash flows. Approximately 95% of the Midstream Entities’ combined cash flows were derived from fee-based services with no direct commodity exposure during 2014. Midstream Holdings has entered into 10-year, fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which Midstream Holdings or its subsidiary will provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Midstream Holdings’ gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. These agreements also include five-year minimum volume commitments and annual rate escalators. Please read “—Midstream Holdings’ Contractual Relationship with Devon.” The Midstream Entities will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.

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Integrated midstream services. The Midstream Entities span the energy value chain by providing natural gas, NGL, crude oil, condensate and water services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing and selling natural gas, producing, fractionating, transporting, storing and selling NGLs, and gathering, transporting, storing and trans-loading crude oil and condensate. The Midstream Entities believe their ability to provide all of these services gives them an advantage in competing for new opportunities because they can provide substantially all services that producers, marketers and others require to move natural gas, NGLs, crude oil and condensate from the wellhead to the market on a cost-effective basis.

•	Financial flexibility to pursue expansion and acquisition opportunities. The Midstream Entities believe their stable cash flows, strong balance sheet and access to debt and equity capital markets provide them with the financial flexibility to competitively pursue acquisition and expansion opportunities and to execute their strategy across capital market cycles.

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Experienced management team. The Midstream Entities believe their management team has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. The Midstream Entities’ management team has an average of over 20 years of experience in the energy industry. The Midstream Entities believe this team provides them with a strong foundation for evaluating growth opportunities and operating their assets in a safe, reliable and efficient manner.

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•	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 11.0 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 a capacity of approximately 7.0 Bcf; 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.

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•	Transmission Systems. The Midstream Entities' transmission systems in Texas include approximately 260 miles of pipeline with an aggregate capacity of approximately 1.3 Bcf/d and consist of the following:

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North Texas Pipeline. The Partnership’s North Texas Pipeline (“NTPL”) is a 140-mile pipeline extending from an area near Fort Worth, Texas to a point near Paris, Texas and connects production from the Barnett Shale to markets in north Texas accessed by the Natural Gas Pipeline Company of America, LLC, Kinder Morgan, Inc., Houston Pipeline Company, L.P., Atmos Energy Corporation and Gulf Crossing Pipeline Company, LLC. The NTPL has approximately 375 MMcf/d of capacity and 18,960 horsepower of compression and, for the period March 7, 2014 through December 31, 2014, the average throughput on the NTPL was approximately 338,000 MMBtu/d.

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Acacia transmission system. The Acacia transmission system, which is owned by Midstream Holdings, is a 120-mile pipeline that connects production from the Barnett Shale to markets in north Texas accessed by Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners and GDF Suez. The Acacia transmission system has approximately 920 MMcf/d of capacity and 17,000 horsepower of compression and, for the year ended December 31, 2014, average throughput was approximately 733,900 MMBtu/d. Devon is the Acacia transmission system’s only customer and has entered into a 10-year fixed-fee transportation agreement that covers transmission services on the Acacia transmission pipeline and includes annual rate escalators.

•	Processing and Fractionation Facilities. The Midstream Entities' processing facilities in Texas include six gas processing plants with total processing throughput that averaged 1,145,749 MMBtu/d for the year ended December 31, 2014 and our 38.75% interest in GCF and consist of the following:

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Bridgeport processing facility. The Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is owned by Midstream Holdings and is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants that have a total of 790 MMcf/d of processing capacity and 15 MBbls/d of NGL fractionation capacity, respectively. For the year ended December 31, 2014, throughput volumes at the Bridgeport processing facility averaged 788,700 MMBtu/d of natural gas. Devon is the Bridgeport facility’s largest customer with approximately 717,700 MMBtu/d of natural gas processed for the year ended December 31, 2014, which represented approximately 91% of the total volumes processed at the facility during such period. In March 2014, Devon and Midstream Holdings entered into a 10-year, fixed-fee processing agreement pursuant to which Midstream Holdings provides processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes a five-year minimum volume commitment from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility as well as annual rate escalators.

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Silver Creek processing complex. The Partnership’s Silver Creek processing complex, located in Weatherford, Azle and Fort Worth, Texas, includes three processing plants. The Partnership’s Silver Creek plants have a total of 280 MMcf/d of processing capacity, with the Azle Plant, Silver Creek Plant and Goforth Plant accounting for 50 MMcf/d, 200 MMcf/d and 30 MMCf/d of processing capacity, respectively. For the period March 7, 2014 through December 31, 2014, throughput volumes at the Silver Creek processing facility averaged 283,600 MMBtu/d of natural gas.

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Permian Basin assets. The Partnership’s Permian Basin assets consist of its Deadwood natural gas processing plant, its Bearkat natural gas processing plant and gathering facilities, and its Mesquite Terminal fractionator. The Partnership has a 50% undivided working interest in the Deadwood processing facility which is located in Glasscock County, Texas. The Deadwood plant is supported by acreage dedication from a major producer in the Permian Basin. The Deadwood processing facility has a total capacity of 58 MMcf/d and total processing throughput that averaged 71,000 MMBtu/d for the period March 7, 2014 through December 31, 2014. The Mesquite Terminal, which has 15,000 BBls/d of fractionation capacity, is located in Midland County and serves as a terminal for third-party raw-make NGLs. The Partnership is also transloading crude oil and condensate at this facility. The Bearkat facility came online in the third quarter of 2014 and consists of

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Gulf Coast Fractionators. Midstream Holdings is entitled to receive the economic benefits and burdens of the 38.75% interest in Gulf Coast Fractionators held by Devon, with the remaining interests owned 22.50% by Phillips 66 and 38.75% by Targa Resources Partners. Gulf Coast Fractionators owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 is the operator of the fractionator. Gulf Coast Fractionators receives raw mix NGLs from customers, fractionates the raw mix and redelivers the finished products to the customers for a fee. The facility has a capacity of approximately 145 MBbls/d. The plant fractionated 44,000 Bbls/d of liquids during 2014.

•	Gathering Systems. The Midstream Entities' gathering systems in Texas include approximately 3,902 miles of pipeline with total throughput of approximately 1,866,000 MMBtu/d for the year ended December 31, 2014 and consist of the following:

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Bridgeport rich gathering system. This rich natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 1,922 miles of pipeline segments with approximately 145,000 horsepower of compression. A substantial majority of the natural gas gathered on the system is delivered to the Bridgeport processing facility. For the year ended December 31, 2014, throughput volumes on the Bridgeport rich gathering system averaged 826,300 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport rich gathering system with approximately 751,900 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 91% of the total throughput on the system during such period. As described above, Devon and Midstream Holdings have entered into a 10-year, fixed-fee gathering agreement pursuant to which Midstream Holdings provides gathering services on the Bridgeport system, which includes a five-year minimum volume commitment from Devon of a combined 850 MMcf/d of natural gas delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.

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Bridgeport lean gathering system. This lean natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 935 miles of pipeline segments with approximately 59,000 horsepower of compression. Natural gas gathered on this system is delivered to the Acacia transmission system and intrastate pipelines without processing. For the year ended December 31, 2014, throughput volumes on the Bridgeport lean gathering system averaged 245,900 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport lean gathering system with approximately 228,700 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 93% of the total throughput on the system during such period. As described above, Devon and Midstream Holdings have entered into a 10-year, fixed-fee gathering and processing agreement that covers gathering services on the Bridgeport system.

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East Johnson County gathering system. This natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 290 miles of pipeline segments. Natural gas gathered on this system is delivered to intrastate pipelines without processing. For the year ended December 31, 2014, throughput volumes on the East Johnson County gathering system averaged 193,500 MMBtu/d of natural gas. Devon is the largest customer on the East Johnson County gathering system with approximately 181,900 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 94% of the total throughput on the system during such period. In March 2014, Devon and Midstream Holdings entered into a 10-year, fixed-fee gathering agreement pursuant to which Midstream Holdings provides gathering services on the East Johnson County gathering system, which includes a five-year minimum volume commitment from Devon of 125 MMcf/d of natural gas delivered for gathering into the East Johnson County gathering system as well as annual rate escalators.

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Silver Creek gathering systems. The Partnership’s Silver Creek gathering system includes two gathering systems. The Partnership’s north Texas gathering system, which we refer to as NTG, consists of approximately 690 miles of gathering lines with approximately 112,900 horsepower of compression and had an average throughput of approximately 608,700 MMBtu/d for the period March 7, 2014 through December 31, 2014. The Denton system consists of approximately 35 miles of gathering lines and had an average throughput of approximately 11,600 MMBtu/d for the period March 7, 2014 through December 31, 2014.

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Howard Energy Partners (“HEP”). HEP owns and operates over 500 miles of pipeline and a 200 MMcf/d processing plant, serving production from the Eagle Ford, Escondido, Olmos, Pearsall and other formations in south Texas and pursues a growth strategy focused on the needs of south Texas producers. HEP’s system has 145 MMcf/d of amine treating capacity and more than 9,000 horsepower of compression. In addition, HEP has a 10 MBbls/d stabilizer in Live Oak County and a 220 MBbls/d liquids storage terminal near Brownsville, Texas. As of December 31, 2014, the Partnership owned a 30.6% interest in HEP and accounted for this investment under the equity method of accounting. The Partnership includes its equity investment in HEP in its corporate segment. Alinda Capital Partners owns a 59% capital interest in HEP.

•	Cana system. Midstream Holdings' Cana gathering and processing system is located in the Cana-Woodford Shale in West Central Oklahoma and consists of the following:

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Cana processing facilities. Midstream Holdings' Cana processing facilities include a multi-train 350 MMcf/d cryogenic processing plant and a crude oil and condensate stabilization facility. For the year ended December 31, 2014, throughput volumes at the Cana processing facility averaged 368,400 MMBtu/d. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners and ONEOK Partners. Devon is the primary customer of the Cana processing facilities and has entered into a 10-year, fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides processing services for natural gas delivered by Devon to the Cana processing facility. This contractual arrangement includes a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

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Cana gathering system. Midstream Holdings' Cana gathering system includes an approximately 340-mile gathering system with approximately 87,500 horsepower of compression. For the year ended December 31, 2014, the Cana system gathered approximately 413,900 MMBtu/d of gas. Devon is the primary customer of the Cana gathering system and, as described above, has entered into a 10-year, fixed-fee gathering agreement with Midstream Holdings pursuant to which Midstream Holdings provides gathering services on the Cana gathering system and that includes a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered for gathering into the Cana gathering system.

•	Northridge system. Midstream Holdings' Northridge gathering and processing system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and consists of the following:

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Northridge processing plant. Midstream Holdings' Northridge processing plant has 200 MMcf/d of processing capacity. For the year ended December 31, 2014, throughput volumes at the Northridge processing facility averaged 73,400 MMBtu/d. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enable Midstream Partners and MarkWest. In August 2014, Linn Energy acquired certain of Devon's southeastern Oklahoma assets and became the largest customer of the Northridge processing facility. In connection with this acquisition Linn Energy assumed Devon's 10-year fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides processing services for natural gas delivered to the Northridge processing facility. This contractual arrangement includes a five-year minimum volume commitment of 40 MMcf/d of natural gas delivered to the Northridge processing facility as well as annual rate escalators.

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Northridge gathering system. Midstream Holdings' Northridge gathering system includes an approximate 140-mile gathering system with approximately 17,900 horsepower of compression. For the year ended December 31, 2014, the Northridge system gathered 56,900 MMBtu/d of gas. Linn Energy is the only customer on the Northridge gathering system and, as described above, has entered into a 10-year fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides gathering services on the Northridge gathering system. This contract includes a five-year minimum volume commitment from Linn Energy of 40 MMcf/d of natural gas delivered for gathering into the Northridge gathering system.

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•	LIG Assets. The LIG system includes gathering and transmission systems with total capacity of approximately 4.0 Bcf/d, processing facilities with a total processing capacity of approximately 335 MMcf/d and fractionation facilities with total capacity of 10,800 Bbls/d.

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The LIG gathering and transmission pipeline system is comprised of the 3,320-mile southern system, which has a capacity in excess of 1.5 Bcf/d and approximately 31,318 horsepower of compression, and the 815-mile northern system, which has a capacity of 465 MMcf/d and approximately 47,330 horsepower of compression. The south system has access to both rich and lean gas supplies from onshore production in south central and southeast Louisiana. LIG has a variety of transportation and industrial sales customers in the south, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans. In the north, the LIG system serves the natural gas fields south of Shreveport, Louisiana and extends into the Haynesville Shale gas play in north Louisiana. The Partnership’s north Louisiana system is connected to its south Louisiana system and has the capacity to move approximately 145 MMcf/d of gas to our markets in the south. The Partnership’s LIG gathering system had an average throughput of approximately 449,700 MMbtu/d for the period March 7, 2014 through December 31, 2014.

•	The south system also includes two operating, on-system processing plants, the Partnership’s Gibson and Plaquemine plants, with 110 MMcf/d and 225 MMcf/d of processing capacity, respectively. For the period March 7, 2014 through December 31, 2014, throughput volumes on the LIG processing system averaged 193,400 MMBtu/d of natural gas.

•	The Plaquemine plant also has a fractionation capacity of 10,800 Bbls/d of raw-make NGL products, and total volume for fractionated liquids at Plaquemine averaged approximately 4,500 Bbls/d for the period March 7, 2014 through December 31, 2014.

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The Gulf Coast gathering and transmission system is comprised of 1,120 miles of onshore systems with a capacity of 1.2 Bcf/d, approximately 37,785 horsepower of compression, underground storage facilities with a storage capacity of 4.2 Bcf of active storage capacity, 7.0 Bcf of inactive storage capacity, and Henry Hub transfer services with a capacity of 2.1 Bcf/d. The onshore system has access to the Gulf Coast and the industrial rich Mississippi River corridor, which is seeing an abundance of new growth in chemical and fertilizer plants. The onshore system had an average throughput of 157,000 MMBtu/d from November 1, 2014 (the date of acquisition) through December 31, 2014. The offshore system is comprised of 215 miles of pipeline with a capacity of 0.3 Bcf/d. The average throughput for the period November 1, 2014 through December 31, 2014 was 8,500 MMBtu/d.

•	South Louisiana NGL and Processing Assets. The Partnership’s south Louisiana NGL and natural gas processing assets include approximately 600 miles of liquids transport lines, processing and fractionation assets and underground storage.

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Cajun-Sibon Pipeline System. The Cajun-Sibon pipeline system consists of approximately 600 miles of raw make NGL pipelines with a current system capacity of approximately 130,000 Bbls/d. The pipelines transport unfractionated NGLs, referred to as raw make, from areas such as the Liberty, Texas interconnects near Mont Belvieu and from the Partnership’s Eunice and Pelican processing plants in south Louisiana to either the Riverside or Eunice fractionators or to third party fractionators when necessary.

•	Processing Facilities. The Partnership’s processing facilities in south Louisiana include three gas processing plants, of which only one is currently operational, with total processing throughput that averaged 354,000 MMBtu/d for the period March 7, 2014 through December 31, 2014 and two fractionation facilities that averaged 115,500 Bbls/d for the period March 7, 2014 through December 31, 2014.

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Pelican Processing Plant. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. For the period March 7, 2014 through December 31, 2014, the plant processed approximately 336,000 MMBtu/d of natural gas. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. This plant

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Blue Water Gas Processing Plant. The Partnership operates and owns a 64.29% interest in the Blue Water gas processing plant. The Blue Water plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. The plant has a net capacity with respect to the Partnership’s interest of approximately 300 MMcf/d. The plant is not expected to operate in the future unless fractionation spreads are favorable and volumes are sufficient to run the plant.

•	Eunice Processing Plant. The Eunice processing plant is located in south central Louisiana and has a capacity of 475 MMcf/d of natural gas. In August 2013, the Partnership shut down the Eunice processing plant due to adverse economics driven by low NGL prices and low processing volumes, which the Partnership does not see improving in the near future based on forecasted prices.

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Plaquemine Fractionation Facility. The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and is connected to the Partnership's Cajun-Sibon pipeline. The Plaquemine fractionation facility has a capacity of approximately 100,000 Bbls/d, and produces purity ethane and propane for sale by pipeline to long-term markets with the butane and heavier products sent to our Riverside facility for further processing. The plant commenced operations during September and fractionated 49,700 Bbls/d of liquids during the fourth quarter of 2014.

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Eunice Fractionation Facility. The Eunice fractionation facility is located in south central Louisiana. The Eunice fractionation facility has a capacity of 55,000 Bbls/d of liquid products, including ethane, propane, iso-butane, normal butane and natural gasoline, and is directly connected to the southeast propane market and pipelines to the Anse La Butte storage facility. The plant fractionated 48,600 Bbls/d for the period March 7, 2014 through December 31, 2014.

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Riverside Fractionation Facility. The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of approximately 28,000 Bbls/d of liquids delivered by the Cajun-Sibon pipeline system from the Eunice and Pelican processing plants or by third-party truck and rail assets. The Riverside fractionator was converted to a butane-and-heavier facility during 2014 in conjunction with the Cajun-Sibon II project. The Riverside facility has above-ground storage capacity of approximately 233,000 Bbls. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges. Total volumes for fractionated liquids at Riverside averaged 17,200 Bbls/d for the year ended December 31, 2014. During the periods of full operation at Riverside for 2014 (excluding the 65 days of shut down related to the Cajun-Sibon II project completion), the average throughput was 22,000 Bbls/d.

•	Napoleonville Storage Facility.    The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of 3.2 million barrels of underground storage comprised of two existing caverns. The caverns are currently operated in propane and butane service, and space is leased to customers for a fee.

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•	rates, services, and terms and conditions of service;

•	the certification and construction of new facilities;

•	the extension or abandonment of services and facilities;

•	the maintenance of accounts and records;

•	the acquisition and disposition of facilities;

•	maximum rates payable for certain services;

•	the initiation and discontinuation of services;

•	internet posting requirements for available capacity, discounts and other matters;

•	pipeline segmentation to allow multiple simultaneous shipments under the same contract;

•	capacity release to create a secondary market for transportation services;

•	relationships between affiliated companies involved in certain aspects of the natural gas business;

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•	market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and

•	participation by interstate pipelines in cash management arrangements.

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•	the amount of natural gas transported in their gathering and transmission pipelines;

•	the level of the Midstream Entities’ processing operations;

•	the fees the Midstream Entities charge and the margins they realizes for their services;

•	the prices of, levels of production of and demand for crude oil, condensate, NGLs and natural gas;

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the volume of natural gas the Midstream Entities gather, compress, process, transport and sell, the volume of NGLs the Midstream Entities process or fractionate and sell, the volume of crude oil the Midstream Entities handle at their crude terminals, the volume of crude oil and condensate the Midstream Entities gather, transport, purchase and sell, the volumes of condensate stabilized and the volumes of brine the Partnership disposes;

•	the relationship between natural gas and NGL prices; and

•	the Midstream Entities’ level of operating costs.

•	the level of capital expenditures the Midstream Entities make;

•	the cost of acquisitions, if any;

•	the Partnership’s debt service requirements;

•	fluctuations in their working capital needs;

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•	the Partnership’s ability to make working capital borrowings under its bank credit facility to pay distributions;

•	prevailing economic conditions; and

•	the amount of cash reserves established by their respective general partners in their sole discretion for the proper conduct of business.

•	the allocation of shared overhead expenses to the Partnership and us;

•	the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and the Partnership, on the other hand;

•	the determination of the amount of cash to be distributed to the Partnership’s partners and the amount of cash to be reserved for the future conduct of the Partnership’s business;

•	the determination whether to make borrowings under the Partnership’s credit facility to pay distributions to partners; and

•	any decision we make in the future to engage in activities in competition with the Partnership.

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•	potential changes in the supply of and demand for oil, natural gas and natural gas liquids (“NGLs”) and related products and services;

•	risks relating to Devon’s exploration and drilling programs, including potential environmental liabilities;

•	adverse effects of governmental and environmental regulation; and

•	general economic and financial market conditions.

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•	availability and adequacy of infrastructure to gather and process supply into and out of the Midstream Entities’ systems.

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•	the impact of weather on the demand for oil and natural gas;

•	the level of domestic oil, condensate and natural gas production;

•	technology, including improved production techniques (particularly with respect to shale development);

•	the level of domestic industrial and manufacturing activity;

•	the availability of imported oil, natural gas and NGLs;

•	international demand for oil and NGLs;

•	actions taken by foreign oil and gas producing nations;

•	the availability of local, intrastate and interstate transportation systems;

•	the availability of downstream NGL fractionation facilities;

•	the availability and marketing of competitive fuels;

•	the impact of energy conservation efforts; and

•	the extent of governmental regulation and taxation, including the regulation of “greenhouse gases.”

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•	the Partnership’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•	the Partnership’s funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of the Partnership’s cash flows required to make interest payments on its debt;

•	the Partnership’s debt level will make it more vulnerable to general adverse economic and industry conditions; and

•	limit the Partnership’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates.

•	adverse weather conditions, including hurricanes and tropical storms;

•	delays or decreases in production, the availability of equipment, facilities or services; and

•	changes in the regulatory environment.

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Ethane.  Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.

•

Propane.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for the Midstream Entities’ propane may be reduced during periods of warmer-than-normal weather.

•

Normal Butane.  Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

•	Isobutane.  Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

•	Natural Gasoline.  Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

•	incur subsidiary indebtedness;

•	engage in transactions with its affiliates;

•	consolidate, merge or sell substantially all of its assets;

•	incur liens;

•	enter into sale and lease back transactions; and

•	change business activities the Partnership conduct.

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•	the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;

•	the diversion of management’s attention from other business concerns;

•	the failure to realize expected volumes, revenues, profitability or growth;

•	the failure to realize any expected synergies and cost savings;

•	the coordination of geographically disparate organizations, systems and facilities;

•	the assumption of unknown liabilities;

•	the loss of customers or key employees from the acquired businesses;

•	a significant increase in the Midstream Entities’ indebtedness; and

•	potential environmental or regulatory liabilities and title problems.

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•	damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;

•	inadvertent damage from construction and farm equipment;

•	leaks of natural gas, NGLs, crude oil, condensate and other hydrocarbons;

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•	induced seismicity;

•	rail accidents, barge accidents and truck accidents; and

•	fires and explosions.

•	hedging can be expensive, particularly during periods of volatile prices;

•	the Partnership’s counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and

•	available hedges may not correspond directly with the risks against which the Partnership seeks protection. For example:

•	the duration of a hedge may not match the duration of the risk against which the Partnership seeks protection;

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•	variations in the index the Partnership uses to price a commodity hedge may not adequately correlate with variations in the index the Partnership uses to sell the physical commodity (known as basis risk); and

•

the Partnership may not produce or process sufficient volumes to cover swap arrangements the Partnership enters into for a given period. If the Partnership’s actual volumes are lower than the volumes the Partnership estimated when entering into a swap for the period, it might be forced to satisfy all or a portion of its derivative obligation without the benefit of cash flow from the sale or purchase of the underlying physical commodity, which could adversely affect the Partnership’s liquidity.

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•	federal income taxes, which we are required to pay because we are taxed as a corporation;

•	the expenses of being a public company;

•	other general and administrative expenses;

•	capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s then-current general partner interest, to the extent the board of directors of the General Partner exercises its option to do so; and

•	cash reserves our board of directors believes are prudent to maintain.

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•	17,431,152 common units representing an aggregate 7% limited partner interest in the Partnership as of December 31, 2014;

•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest as of December 31, 2014 and all of the incentive distribution rights in the Partnership; and

•	50.0% limited partner interest in Midstream Holdings as of December 31, 2014 and 25% limited partner interest in Midstream Holdings as of February 17, 2015.

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•	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 11.0 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.

•

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

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•	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.

•

Subsequent to March 7, 2014, we own a 50% direct ownership interest in Midstream Holdings and indirectly own an additional interest of approximately 3% of Midstream Holdings through our ownership in the Partnership which owns the remaining 50% interest in Midstream Holdings rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. Our financial statements after March 7, 2014 consolidate all of Midstream Holdings’ financial results with ours in accordance with GAAP and ENLK’s 47% interest not owned by us in Midstream Holdings is reflected as a non-controlling interest. On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings to the Partnership in exchange for 31.6 million Class D Common Units in the Partnership. See “Recent Growth Developments.”

•	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 assets comprised all of Devon’s U.S.-midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as a contractual right to the burdens and benefits of its 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the consummation of the business combination. Assets that were not contributed to Midstream Holdings are included in discontinued operations.

•

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

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•	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;

•	our ability to negotiate favorable sales agreements;

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

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•	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.

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•	failure to pay any principal or interest when due;

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

•	bankruptcy or other insolvency events involving us.

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1.

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

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2.

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

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

*	weighted average

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*	Denotes chairman of committee.

**	Denotes independent director.

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•	The Governance and Compensation Committee has general oversight responsibility for the Company’s compensation plans, policies and programs. This general oversight responsibility includes reviewing and approving compensation policies and practices for all employees, overall payroll, bonus plans, overall bonus payouts, setting bonus targets, and other general compensation matters.

•	The Governance and Compensation Committee is authorized to make awards under the Company’s long-term incentive plans. The Governance and Compensation Committee will review and approve the total number of awards to be made from time to time. The allocation of those awards to employees that are not “Executive Officers” (as defined below) will be made by the Chief Executive Officer.

•

Not less than annually, the Governance and Compensation Committee will review the Company’s executive compensation plans and policies. The Governance and Compensation Committee will review the corporate goals and objectives relevant to the compensation of the Chief Executive Officer, any officer designated as a “Section 16 Officer” and each other officer that the Governance and Compensation Committee or the Board may designate (collectively referred to as the “Executive Officers”). The Governance and Compensation Committee will evaluate the performance of the Chief Executive Officer, and, together with the Chief Executive Officer, the performance of each other Executive Officer. The Governance and Compensation Committee will at least annually review each Executive Officer’s base compensation, bonus, awards under the Company’s long-term incentive plans, and any other compensation, and make recommendations to the Board regarding each Executive Officer’s compensation. No Executive Officer may be present during any voting or deliberations by the Governance and Compensation Committee regarding his or her compensation.

•	The Governance and Compensation Committee will review the policies of the Company and the General Partner regarding the compensation of directors serving on the Board and the Board of Directors of the General Partner (the “GP Board”) and make recommendations to the Board regarding such compensation, including meeting fees, committee fees and equity-based compensation.

•

The Governance and Compensation Committee will review and oversee the Company’s succession plans and leadership development programs for the Chief Executive Officer and the other Executive Officers, including reviewing from time to time reports and presentations regarding human resources, executive development, staffing, training, performance management, career development and other related matters as necessary.

•	The Governance and Compensation Committee will review and approve the terms of any employment contracts, severance agreements, or other contracts with any Executive Officer, provided that the Board reserves to itself the approval of the compensation of the Executive Officers.

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•	in order to achieve its goals, it is critical that we attract, retain and motivate highly qualified executive officers;

•	base salary and bonus opportunities must be competitive in order to attract, retain and motivate highly qualified executive officers;

•	equity-based incentive compensation should represent a significant portion of the executive’s total compensation in order to retain and incentivize highly qualified executives and align their individual long-term interests with the interests of unitholders;

•	compensation programs must be sufficiently flexible to address special circumstances, which include payments under retention plans specifically targeted to retain highly qualified officers during challenging times; and

•	the overall compensation program should drive performance and reward contributions in support of our business strategies and achievements.

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•	base salary;

•	annual bonus plan awards;

•	long-term incentive plan awards; and

•	retirement and health benefits.

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•

Options.  Options are rights to purchase a specified number of our common units at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot exceed ten years from the date of grant. Options will be exercisable on such terms as the Governance and Compensation Committee determines. The Governance and Compensation Committee will also determine the time or times at which, and the circumstances under which, an option may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, form of consideration payable in settlement, method by or forms in which common units will be delivered to participants, and whether or not an option will be in tandem with a UAR award. Under no circumstances will distributions or DERs be granted or made with respect to option awards. An option granted to an employee may consist of an option that complies with the requirements of Section 422 of the Internal Revenue Code, referred to in the 2014 Plan as an “incentive unit option.” In the case of an incentive unit option granted to an employee who owns (or is deemed to own) more than 10% of the total combined voting power of all classes of units, the exercise price of the option must be at least 110% of the fair market value per common unit on the date of grant and the term of the option cannot exceed five years from the date of grant.

•

Unit Appreciation Rights or UARs.  A UAR is a right to receive an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the UAR. UARs will be exercisable on such terms as the Governance and Compensation Committee determines. The Governance and Compensation Committee will also determine the time or times at which and the circumstances under which a UAR may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, method of settlement, form of consideration payable in settlement, method by or forms in which common units will be delivered or deemed to be delivered to participants, whether or not a UAR will be in tandem with an option award, and any other terms and conditions of any UAR. UARs may be either freestanding or in tandem with other awards. Under no circumstances will distributions or DERs be granted or made with respect to UAR awards.

•

Restricted Units.  A restricted unit is a grant of a common unit subject to a substantial risk of forfeiture, restrictions on transferability and any other restrictions determined by the Governance and Compensation Committee. The Governance and Compensation Committee may provide, in its discretion, that the distributions made by us with respect to the restricted units will be subject to the same forfeiture and other restrictions as the restricted unit and, if so restricted, such distributions will be held, without interest, until the restricted unit vests or is forfeited with the unit distribution right being paid or forfeited at the same time, as the case may be. In addition, the Governance and Compensation Committee may provide that such distributions be used to acquire additional

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Restricted Incentive Units.  Restricted incentive units are rights to receive cash, common units or a combination of cash and common units at the end of a specified period. Restricted incentive units may be subject to restrictions, including a risk of forfeiture, as determined by the Governance and Compensation Committee. The Governance and Compensation Committee may, in its sole discretion, grant DERs with respect to restricted incentive units.

•

Distribution Equivalent Rights or DERs.  DERs entitle a participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. DERs may be granted as a stand-alone award or with respect to awards other than restricted units, options or UARs. Subject to Section 409A of the Internal Revenue Code, payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the Governance and Compensation Committee.

•	Unit Awards.  The 2014 Plan permits the grant of unit awards, which are common units that are not subject to vesting restrictions.

•	Cash Awards.  The 2014 Plan permits the grant of cash awards, which are awards denominated and payable in cash.

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Performance Awards.  Performance awards represent a participant’s right to receive an amount of cash, common units, or a combination of both, contingent upon the annual attainment of specified performance measures within a specified period. The Governance and Compensation Committee or other committee that is intended to satisfy the requirements of Section 162(m) of the Internal Revenue Code (the “Section 162(m) Committee”), as applicable, will determine the applicable performance period, the performance goals and such other conditions that apply to each performance award. In addition, the 2014 Plan permits, but does not require, the Governance and Compensation Committee or the Section 162(m) Committee, as applicable, to structure any performance award made to a covered employee as qualified performance-based compensation under Section 162(m) of the Internal Revenue Code. Section 162(m) of the Internal Revenue Code generally limits the deductibility for federal income tax purposes of annual compensation paid to certain top executives of a company to $1 million per covered employee in a taxable year (to the extent such compensation does not constitute qualified performance-based compensation under Section 162(m) of the Internal Revenue Code). Prior to the payment of any compensation based on the achievement of performance goals applicable to performance awards that are intended to provide qualified performance-based compensation under Section 162(m) of the Internal Revenue Code, the Governance and Compensation Committee or the Section 162(m) Committee, as applicable, must certify in writing that applicable performance goals and any of the material terms thereof were, in fact, satisfied.

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•

Unit Options.  The GP Plan currently permits the grant of options covering common units. These are rights to purchase a specified number of common units of the Partnership at a specified price. All unit option grants will have an exercise price that is not less than 100% the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the GP Committee and the term of the options cannot exceed ten years from the date of grant. In addition, unit options may, pursuant to their terms, become exercisable upon a change of control of the Partnership or the General Partner. The General Partner will be entitled to reimbursement by the Partnership for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by the Partnership. If the Partnership issues new common units upon exercise of the unit options, the total number of common units outstanding will increase, and the General Partner will pay the Partnership the proceeds it received from the optionee upon exercise of the unit option. Any unit options granted pursuant to the GP Plan have been designed to furnish additional compensation to employees, consultants, independent contractors and directors and to align their economic interests with those of common unitholders.

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Restricted Incentive Units.  The GP Plan currently permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive common units of the Partnership upon the vesting of such restricted incentive units. The GP Committee will determine the terms, conditions and limitations applicable to any awards of restricted incentive units. Awards of restricted incentive units will have a vesting period established in the sole discretion of the GP Committee, which may include, without limitation, vesting upon the achievement of specified performance goals. In addition, the restricted incentive units may, pursuant to their terms, vest upon a change of control of the Partnership or the General Partner. Common units to be delivered upon the vesting of restricted incentive units may be common units acquired by the General Partner in the open market, common units already owned the General Partner, common units acquired by the General Partner directly from us or any other person or any combination of the foregoing. The General Partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted incentive units, the total number of common units outstanding will increase. The GP Committee, in its discretion, may grant tandem DERs with respect to restricted incentive units which entitles a participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. The GP Committee may provide, in its discretion, that the DERs will be subject to the same forfeiture and other restrictions as a restricted incentive unit and, if so restricted, such distributions will be held, without interest, until the restricted incentive unit vests or is forfeited with the distribution being paid or forfeited at the same time, as the case may be. The Partnership intends for the issuance of the common units upon vesting of the restricted incentive units under the GP Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under current policy, GP Plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units.

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(1)

Bonuses include all payments made under the Annual Bonus Plan. For 2014, 2013 and 2012, the named executive officers received bonuses in the form of equity awards that immediately vest. The amounts shown for 2014, 2013 and 2012 represent the grant date fair value of awards computed in accordance with FASB ASC 718. Such awards were allocated 50% in restricted units or restricted incentive units of EnLink Midstream, LLC and 50% in restricted units or restricted incentive units of EnLink Midstream Partners, LP See “Bonus Awards” above.

(2)	The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718. See Note 9 to our audited financial statements included in Item 8 herein for the assumptions made in our valuation of such awards.

(3)	Non-Equity Incentive Plan Compensation includes payments made under the cash bonus plan funded by EnLink Midstream Partners, LP in January 2014, which was designed to reward a broad base of employees for successful consummation of the transactions with Devon. These amounts were awarded in February 2014.

(4)

Amount of all other compensation for Mr. Barry Davis includes professional organization and social club dues, a matching 401(k) contribution of $15,600, distributions or dividends on restricted units and restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $144,228 in 2014, distributions on restricted units or restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount $251,576 in 2014 and a $258,968 cash award for Mr. Davis’ waiver of certain rights with respect to the acceleration and vesting of awards under applicable long-term incentive plans in connection with the consummation of the business combination with Devon.

(5)

Amount of all other compensation for Mr. Steve Hoppe includes professional organization and social club dues, a matching 401(k) contribution of $15,600, distributions on restricted units and restricted incentive units and performance units of EnLink Midstream, LLC in the amount of $21,516 in 2014 and distributions on restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount of $43,480 in 2014.

(6)

Amount of all other compensation for Mr. Mac Hummel includes professional organization and social club dues, a matching 401(k) contribution of $14,792, distributions on restricted units and restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $17,213 in 2014 and distributions on restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount of $39,384 in 2014.

(7)

Amount of all other compensation for Mr. Michael Garberding includes professional organization and social club dues, a matching 401(k) contribution of $15,600, distributions or dividends on restricted units or restricted incentive units of EnLink Midstream, LLC in the amount of $93,893 in 2014, distributions on restricted units or restricted incentive units of EnLink Midstream Partners, LP in the amount of $161,212 in 2014 and a $196,944 cash award for Mr. Garberding’s waiver of certain rights with respect to the acceleration and vesting of awards under applicable long-term incentive plans in connection with the consummation of the business combination with Devon.

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(8)	Amount of all other compensation for Mr. Stan Golemon includes a matching 401(k) contribution of $15,600, dividends or distributions on restricted units or restricted incentive units of EnLink Midstream, LLC in the amount of $38,522 in 2014 and distributions on restricted units or restricted incentive units of EnLink Midstream Partners, LP in the amount of $62,977 in 2014.

(1)	These grants vested on March 14, 2014.

(2)	These grants include right to receive dividends or DERs on restricted units or restricted incentive units, as applicable, if made on unrestricted common units during the restricted period unless otherwise forfeited and vest 100% on March 7, 2017.

(3)	These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on March 7, 2016.

(1)	These grants vested on March 14, 2014.

(2)	These grants include Distribution Equivalent Rights (DERs) that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on March 7, 2017.

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(3)	These grants include Distribution Equivalent Rights (DERs) that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on March 7, 2016.

(1)	Restricted incentive units vested on January 1, 2015.

(2)	The closing price for the common units was $35.56 as of December 31, 2014.

(3)	Restricted incentive units vest on January 1, 2016.

(4)	Restricted incentive units vest on March 7, 2017.

(5)	Restricted incentive units vest on July 31, 2016.

(6)	Restricted incentive units vest on March 7, 2016.

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(1)	Restricted incentive units vested on January 1, 2015.

(2)	The closing price for the common units was $29.01 as of December 31, 2014.

(3)	Restricted incentive units vest on January 1, 2016.

(4)	Restricted incentive units vest on March 7, 2017.

(5)	Restricted incentive units vest on July 31, 2016.

(6)	Restricted incentive units vest on March 7, 2016.

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(1)	Consists of 6,821 units at $36.08 per unit, 23,148 units at $41.09 per unit and 51,919 units at $36.16 per share.

(2)	Consists of 31,944 units at $27.60 per unit, 7,453 units at $33.02 per unit and 15,272 units at $29.55 per unit.

(3)	Consists of 3,106 units at $36.08 per unit, 27,778 units at $41.09 per unit and 13,826 units at $36.16 per unit.

(4)	Consists of 8,507 units at $27.60 per unit, 3,393 units at $33.02 per unit and 18,326 units at $29.55 per unit.

(5)	Consists of 1,777 units at $36.08 per unit, 13,286 units at $36.16 per unit and 23,363 units at $39.40 per unit.

(6)	Consists of 8,507 units at $27.60 per unit, 19,296 units at $30.45 per unit and 1,942 units at $33.02 per unit.

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(1)

Each named executive officer is entitled to a lump sum amount equal to two times the Severance Benefit and, when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause or if he terminates employment for good reason (as defined in the Severance Agreement), subject to compliance with certain non-competition and non-solicitation covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(2)	Each named executive officer is entitled to health care benefits equal to a lump sum payment of the estimated monthly cost of the benefits under COBRA for 18 months if he is terminated without cause, or if he terminates employment for good reason.

(3)

Each named executive officer is entitled to his then current base salary up to the date of termination plus such other fringe benefits (other than any bonus, severance pay benefit, participation in the company's 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the company as earned up to the date of termination if he is terminated for cause (as defined in the Severance Agreement) or he terminates employment without good reason (as defined in the Severance Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(4)

Each named executive officer (except Mr. Golemon) is entitled to a lump sum payment equal to two times the Severance Benefit (three times in the case of the Chief Executive Officer) and, when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause (as defined in the Severance Agreement) or if he terminates employment for good reason (as defined in the Severance Agreement) within one-hundred and twenty (120) days prior to or one (1) year following a change in control (as defined in the Severance Agreement), subject to compliance with certain non-competition, non-solicitation and other covenants described elsewhere in this Annual Report on Form 10-K. A change

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(5)	Each named executive officer is entitled to accelerated vesting of certain outstanding equity awards in the event of a change of control (as defined under the long term incentive plans). These amounts correspond to the values set forth in the table in the section above entitled Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2014.

(1)

Messrs. Crain, Echols, Galvert and Ms. Ricciardello were granted awards of restricted units of EnLink Midstream LLC on March 14, 2014 with a fair market value of $36.08 per unit and that will vest on March 7, 2015 in the following amounts, respectively: 2,772, 1,386, 2,772 and 1,386. Mr. Echols and Ms. Ricciardello were granted awards of restricted incentive units of EnLink Midstream Partners, LP on March 14, 2014 with a fair market value of $33.02 per unit and that will vest on March 7, 2015 in the following amounts, respectively: 1,514 and 1,514. The amounts shown represent the grant date fair value of awards computed in accordance with FASB ACS 718. See Note 11 to our audited financial statements included in Item 8 herein for the assumptions made in our valuation of such awards. At December 31, 2014, Messrs. Crain, Echols, Galvert and Ms. Ricciardello held aggregate outstanding restricted unit awards, in the following amounts, respectively: 2,772, 1,386, 2,772 and 1,386. At December 31, 2014, Mr. Echols and Ms. Ricciardello held aggregate outstanding restricted incentive units of EnLink Midstream Partnership, LP in the following amounts, respectively: 1,514 and 1,514.

(2)	Other Compensation is comprised of distributions on restricted units and distributions on restricted incentive units.

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•	each person who beneficially owns 5% or more of any class of units then outstanding;

•	all the directors of EnLink Midstream Manager, LLC;

•	each named executive officer of EnLink Midstream Manager, LLC; and

•	all the directors and executive officers of EnLink Midstream Manager, LLC as a group.

*	Less than 1%.

(1)	The address of each person listed above is 2501 Cedar Springs, Suite 100, Dallas, Texas 75201, except for Devon Energy Corporation, whose address is 333 W. Sheridan Avenue, Oklahoma City, Oklahoma 73102.

(2)	These individuals each hold an ownership interest in EnLink Midstream Partners, L.P. as indicated in the table above.

(3)	1,000 of these shares are held by the James C. Crain Trust.

•	each person who beneficially owns 5% or more of any class of units then outstanding;

•	all the directors of EnLink Midstream GP, LLC;

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•	each named executive officer of EnLink Midstream GP, LLC; and

•	all the directors and executive officers of EnLink Midstream GP, LLC as a group.

*	Less than 1%

(1)	The address of each person listed above is 2501 Cedar Springs, Suite 100, Dallas, Texas 75201, except for Devon Energy Corporation, whose address is 333 W. Sheridan Avenue, Oklahoma City, Oklahoma 73102.

(2)	These individuals each hold an ownership interest in EnLink Midstream, LLC as indicated in the following table.

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(1)	Our 2014 Long-Term Incentive Plan was approved by our unitholders in March 2014 for the benefit of our officers, employees and directors. See Item 11, “Executive Compensation—Compensation Discussion and Analysis.” The plan, as amended, provides for the issuance of a total of 11,000,000 common units under the plan.

(2)	The number of securities includes 986,472 restricted units that have been granted under our long-term incentive plan that have not vested.

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(a)	Financial Statements and Schedules

1.	See the Index to Financial Statements on page F-1.

2.	Exhibits

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*	Filed herewith.

**	In accordance with the instruction on item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1 and 2.2 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.

†	As required by Item 15(a)(3), this Exhibit is identified as a compensatory benefit plan or arrangement.

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•	17,431,152 common units representing an aggregate 7.1% limited partner interest in the Partnership;

•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest and all of the incentive distribution rights in the Partnership; and

•	50% limited partner interest in Midstream Holdings and 25% limited partner interest in Midstream Holdings as of February 17, 2015.

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•	failure to pay any principal or interest when due;

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

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

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

•	bankruptcy or other insolvency events involving us.

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(1)	Devon retained $13.1 million of the undistributed earnings due from GCF, as of March 7, 2014 when the GCF contractual right allocating the benefits and burdens of the 38.75% ownership interest in GCF to the Partnership became effective. The $13.1 million of the undistributed earnings was reflected as a reduction in the GCF investment on March 7, 2014.

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*	Vested units include 24,314 units withheld for payroll taxes paid on behalf of employees.

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*

Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date. The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

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