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•	88,528,451 common units representing an aggregate 26.5% limited partner interest in the Partnership; and

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•	100.0% ownership interest in the General Partner, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

•	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 calls for our interest in Tall Oaks to the extent not covered by our borrowings;

•	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 (the “GP Board”) exercises its option to do so; and

•	cash reserves the board of directors of EnLink Midstream Manager, LLC, our managing member (the “Managing Member”), 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 1.4 Bcf/d and gathering systems with total capacity of approximately 2.9 Bcf/d.

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•	Oklahoma. The Partnership's 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 (excluding the Oklahoma assets acquired in January 2016 discussed in Recent Growth Developments below).

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Louisiana. The Partnership's Louisiana assets consist of Louisiana Gas and Processing assets which include 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. The Partnership's Louisiana Liquids assets consists of 660 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 198 MBbls/d.

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Crude and Condensate. The Partnership's Crude and Condensate assets consist of approximately 350 miles of crude oil and condensate pipelines. The assets also include 900,000 barrels of above ground storage and a trucking fleet of approximately 150 vehicles comprised of both semi and straight trucks with a current capacity of 85,350 Bbls/d. The current pipeline capacity is 101,100 Bbls/d. Additionally, the Partnership's operations include eight condensate stabilization and natural gas compression stations with combined capacities of over 36,000 Bbls/d of condensate stabilization and 780 MMcf/d of natural gas compression.

•	Corporate. The Partnership's Corporate assets consist of a contractual right to the benefits and burdens associated with Devon's 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) and a 30.6% ownership interest in Howard Energy Partners (“HEP”).

•	Maintain stable cash flows supported by long-term, fee-based contracts. The Partnership will seek to generate cash flows pursuant to long-term, firm contracts with creditworthy customers. The Partnership will continue to pursue opportunities to increase the fee-based and minimum volume commitment components of its contract portfolio to minimize its direct commodity price exposure.

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Maintain strong financial position. The Partnership believes that maintaining a conservative and balanced capital structure and appropriate leverage and other key financial metrics will afford it better access to the capital markets at a competitive cost of capital. The Partnership also believes a strong financial position provides it the opportunity to grow its business in a prudent manner through the cycles in its industry.

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Execute in our core areas. The Partnership believes its assets are positioned in some of the most economic basins in the U.S. as well as key demand centers with growing end-use customers. The Partnership expects to grow certain of its systems organically over time by meeting Devon’s and its other customers’ midstream service needs that result from its drilling activity in the Partnership's areas of operation. The Partnership continually evaluates whether to pursue economically attractive organic expansion opportunities in existing or new areas of operation that allow it to leverage its existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand for its services.

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Devon’s sponsorship. The Partnership expects its relationship with Devon will continue to provide it 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 Partnership's business, due to its approximate 70% ownership interest in us and approximate 28% ownership interest in the Partnership as of December 31, 2015. Approximately 50% of the Partnership's gross operating margin was attributable to commercial contracts with Devon in 2015.

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Strategically-located assets. The Partnership's assets are strategically located in strategic producing regions with the potential for increasing throughput volume and cash flow generation. The Partnership's assets are in areas consistent with Devon's strategic focus. The Partnership's 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 Partnership has developed or is in the process of developing

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Stable cash flows. Approximately 96% of the Partnership's combined cash flows were derived from fee-based services with no direct commodity exposure during 2015. The Partnership currently has approximately eight years remaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which the Partnership will provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Partnership's gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide the Partnership 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 minimum volume commitments that will remain in effect for approximately three more years, as well as annual rate escalators with a remaining term of approximately three years. Additionally, the Partnership's recently acquired Tall Oak assets are supported by Devon with acreage dedications and minimum volume commitments for gathering and processing on Devon’s recently acquired Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) acreage. Please read “—Partnership’s Contractual Relationship with Devon.” The Partnership 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 Partnership spans the energy value chain by providing natural gas, NGL, crude oil and condensate services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing and selling natural gas, producing, fractionating, transporting, stabilizing, storing and selling NGLs, and gathering, transporting, storing and trans-loading crude oil and condensate. The Partnership believes its ability to provide all of these services gives it an advantage in competing for new opportunities because it 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.

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Experienced management team. The Partnership believes its management team has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. The Partnership's management team has an average of over 20 years of experience in the energy industry. The Partnership believes this team provides it with a strong foundation for evaluating growth opportunities and operating its assets in a safe, reliable and efficient manner.

(1)	The Bridgeport gathering and processing contract includes volume commitments to the Bridgeport processing facility as well as the Bridgeport gathering systems.

(2)	The minimum gathering volume commitments and minimum processing volume commitments under this contract escalate on a quarterly basis over the life of the five-year commitment beginning with an average of commitment 37 MMcf/d during 2016 and ending with an average commitment of 230 MMcf/d during 2020.

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Chisholm Plant. The Chisholm Plant, which serves the STACK play, is a cryogenic gas processing plant with a current capacity of 100 MMcf/d. Depending on future volume requirements, the Chisholm Plant could be expanded by an additional 600 MMcf/d for a total processing capacity of 700 MMcf/d. The plant is connected to a 200-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

•	Battle Ridge Plant. The Battle Ridge Plant, which provides us and the Partnership with an entry into the CNOW play, is a cryogenic gas processing plant with a current capacity of 75 MMcf/d. The plant is connected to a 175-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

•	Connecting Pipeline. A 42-mile, 16-inch high-pressure header pipeline with a total capacity of 150 MMcf/d was constructed to connect the Chisolm and Battle Ridge Plant systems. The pipeline went into service in February 2016 and provides customers with additional operational flexibility.

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(1)	Includes power generation units.

(2)	Estimated capacity for gas pipelines is MMcf/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.

(3)	Average throughput for gas pipelines is MMBtu/d. Average throughput for liquids and crude and condensate pipelines is Bbls/d.

(4)	Estimated capacity is comprised of trucking capacity only.

(5)	Estimated capacity is comprised of 11,100 Bbls/d of pipeline capacity and 59,700 Bbls/d of trucking capacity.

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(1)	Volumes are shown net of the Partnership's net contractual right to the burdens and benefits of a 38.75% economic interest in Gulf Coast Fractionators held by Devon.

(2)

The Partnership has two small fractionation facilities of 15 MBbls/d each. The Partnership's Mesquite Terminal in the Permian Basin and its Bridgeport processing plant in North Texas provide operational flexibility for the related processing plants, but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under the Partnership’s current contracts, it does not earn fractionation fees for operating these fractionation facilities so throughput volumes through these facilities are not captured on a routine basis and are not significant to its operating margins.

•	Transmission Systems. The Partnership's transmission systems in Texas include approximately 270 miles of pipeline with an aggregate capacity of approximately 1.3 Bcf/d for the year ended December 31, 2015.

•	North Texas Assets. The Partnership's North Texas transmission systems include 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 year ended December 31, 2015, the average throughput on the NTPL was approximately 315,700 MMBtu/d.

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Acacia transmission system. The Acacia transmission system is a 130-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, 2015, average throughput was approximately 671,300 MMBtu/d. Devon is the Acacia transmission system’s only customer with approximately eight years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.

•	Processing and Fractionation Facilities. The Partnership's processing facilities in Texas include 9 gas processing plants with total processing throughput that averaged 1,222,700 MMBtu/d for the year ended December 31, 2015 and our 38.75% interest in GCF and consist of the following:

•	North Texas Assets. The Partnership's North Texas processing systems include 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 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. For the year ended December 31, 2015, throughput volumes at the Bridgeport processing facility averaged 733,900 MMBtu/d of natural gas. Devon is the Bridgeport facility’s largest customer with approximately 656,500 MMBtu/d of natural gas processed for the year ended December 31, 2015, which represented approximately 90% of the total volumes processed at the facility during such period. The Partnership currently has approximately eight years remaining on a fixed-fee processing agreement with Devon pursuant to which the Partnership provides processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes a minimum

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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 year ended December 31, 2015, throughput volumes at the Silver Creek processing facility averaged 266,300 MMBtu/d of natural gas.

•	Permian Basin processing facilities. The Partnership's Permian Basin processing facilities consist of the following:

•	Bearkat processing facility. The Bearkat natural gas processing facility is located in Glasscock County, Texas and has a total capacity of 75 MMcf/d. The Bearkat plant averaged 28,400 MMBtu/d for the year ended December 31, 2015.

•	Deadwood processing facility. The Deadwood processing facility 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 61,500 MMBtu/d for the year ended December 31, 2015.

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MidMar processing facilities. The MidMar natural gas processing facility is located in the North Midland Basin in Martin County, Texas and includes two processing plants. The MidMar plants have a total of 175 MMcf/d of processing capacity with the East Plant and West Plant accounting for 100 MMcf/d and 75 MMcf/d of processing capacity, respectively. For the period March 16, 2015 to December 31, 2015, throughput volumes at the MidMar facility averaged 159,400 MMBtu/d of natural gas.

•	Lobo processing facility. The Partnership's Lobo natural gas processing facility is located in Loving County, Texas and has a total capacity of 35 MMcf/d. For the period October 1, 2015 to December 31, 2015, throughput volumes at the Lobo facility averaged 21,800 MMBtu/d of natural gas.

•	Gathering Systems. The Partnership's gathering systems in Texas include approximately 4,420 miles of pipeline with total throughput of approximately 1,862,600 MMBtu/d for the year ended December 31, 2015.

•	North Texas Assets. The Partnership's North Texas gathering systems include the following:

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Bridgeport rich gathering system. This rich natural gas gathering system consists of approximately 2,140 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, 2015, throughput volumes on the Bridgeport rich gathering system averaged 760,400 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport rich gathering system with approximately 756,000 MMBtu/d of natural gas gathered for the year ended December 31, 2015, which represented approximately 99% of the total throughput on the system during such period. As described above, the Partnership currently has approximately eight years remaining on a fixed-fee gathering agreement with Devon pursuant to which the Partnership provides gathering services on the Bridgeport system, and such agreement includes a minimum volume commitment from Devon that will remain in effect for approximately three more years 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 consists of approximately 655 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, 2015, throughput volumes on the Bridgeport lean gathering system averaged 231,800 MMBtu/d of natural gas, all of which were attributable to Devon. As described above, the Partnership is a party to fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.

•	East Johnson County gathering system. This natural gas gathering system consists of approximately 290 miles of pipeline segments with approximately 33,850 horsepower of compression. Natural gas gathered on this system is delivered to intrastate pipelines without processing. For the year ended December 31, 2015 throughput volumes on the East Johnson County gathering system averaged

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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 720 miles of gathering lines with approximately 112,874 horsepower of compression and had an average throughput of approximately 478,200 MMBtu/d for the year ended December 31, 2015. The Denton system consists of approximately 35 miles of gathering lines with approximately 29,985 horsepower of compression and had an average throughput of approximately 65,400 MMBtu/d for the year ended December 31, 2015.

•	Permian Basin assets. The Partnership's Permian Basin gathering systems include the following:

•	Bearkat gathering system. The rich natural gas gathering system consists of 270 miles of high and low pressure pipeline with approximately 34,710 horsepower of compression and had an average throughput of approximately 32,300 MMBtu/d for the year ended December 31, 2015.

•	Coronado gathering system. The rich natural gas gathering system consists of 300 miles of high pressure pipeline with approximately 51,740 horsepower of compression. For the period March 16, 2015 to December 31, 2015, throughput volumes averaged 168,800 MMBtu/d.

•	Lobo gathering system. The rich natural gas gathering system consists of 10 miles of gathering pipeline with approximately 2,760 horsepower of compression. For the period October 1, 2015 to December 31, 2015, throughput volumes averaged 21,900 MMBtu/d.

•	Oklahoma processing facilities. The Partnership's processing facilities include the follow:

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Northridge processing plant. The Partnership's Northridge processing plant has 200 MMcf/d of processing capacity. For the year ended December 31, 2015, throughput volumes at the Northridge processing facility averaged 57,700 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 thereby becoming the largest customer of the Northridge processing facility. In connection with this acquisition, effective December 1, 2014, Devon assigned, and Linn Energy assumed, all right, title and interest in Devon's fixed-fee gathering and processing agreement with the Partnership pursuant to which it provides processing services for natural gas delivered to the Northridge processing facility. This contractual arrangement includes a minimum volume commitment that will remain in effect for approximately three more years of 40 MMcf/d of natural gas delivered to the Northridge processing facility and also provides annual rate escalators.

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Cana processing facilities. The Partnership's 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, 2015, throughput volumes at the Cana processing facility averaged 301,900 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 approximately eight years remaining on a fixed-fee gathering and processing agreement with the Partnership pursuant to which it provides processing services for natural gas delivered by Devon to the Cana processing facility. This contractual arrangement includes a minimum volume commitment from Devon that will remain in effect for approximately three more years of 330 MMcf/d of natural gas delivered to the processing facility and also provides annual rate escalators.

•	Oklahoma gathering system. The Partnership's Oklahoma gathering systems include the following:

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Cana gathering system. The Partnership's Cana gathering system is located in the Cana-Woodford Shale in West Central Oklahoma and includes approximately 440-mile gathering system with approximately 87,500 horsepower of compression. For the year ended December 31, 2015, the Cana system gathered approximately 380,300 MMBtu/d of gas. Devon is the primary customer of the Cana gathering system and, as described

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Northridge gathering system. The Partnership's Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and includes approximately 140-mile gathering system with approximately 13,200 horsepower of compression. For the year ended December 31, 2015, the Northridge system gathered 48,300 MMBtu/d of gas. Linn Energy is the only customer on the Northridge gathering system and, as described above, is party to a fixed-fee gathering and processing agreement with the Partnership that covers gathering services on the Northridge gathering system.

•	Louisiana Gas Pipeline and Processing Systems. The Louisiana gas pipeline system includes gathering and transmission systems with a capacity of approximately 4.0 Bcf/d and processing facilities with total processing capacity of approximately 1.7 Bcf/d and underground gas storage of 19.1 Bcf/d.

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Gas Gathering and Transmission Systems. The Partnership's gathering and transmission systems include 3,145 miles of gathering and transmission systems with a total capacity of 4.0 bcf/d. The systems have a combined 97,400 horsepower of compression. The system has access to both rich and lean gas supplies from onshore production in south central and southeast Louisiana and a variety of transportation and industrial sale customers in the south, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans. This system also serves the natural gas fields south of Shreveport, Louisiana and extends into the Haynesville Shale plays in north Louisiana. For the year ended December 31, 2015, throughput volumes on the gathering system averaged 881,000 MMBtu/d of natural gas and throughput volumes on the transmission system averaged 587,300 MMBtu/d of natural gas.

•	Gas Processing and Storage Facilities. The Partnership's processing facilities in Louisiana include five gas processing plants, of which three are currently operational, with total processing throughput that averaged 506,100 MMBtu/d for the year ended December 31, 2015.

•	Plaquemine Processing Plant. The Plaquemine processing plant has 110 MMcf/d of processing capacity. For the year ended December 31, 2015, throughput volumes of the Plaquemine processing plant averaged 161,400 MMBtu/d of natural gas.

•	Gibson Processing Plant. The Gibson processing plant has 225 MMcf/d of processing capacity. For the year ended December 31, 2015, throughput volumes of the Gibson processing plant averaged 38,500 MMBtu/d of natural gas.

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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 year ended December 31, 2015, the plant processed approximately 306,200 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 has an interconnection with the Louisiana gas pipeline system allowing the Partnership to process natural gas from this system at its Pelican plant when markets are favorable.

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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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Belle Rose Gas Storage Facility. The Belle Rose storage facility is located in Assumption Parish, Louisiana and has a total capacity of 10.2 Bcf. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline. This storage facility is expected to go into service during 2016. The storage facility includes three compressors with total of 9,637 horsepower.

•	Sorrento Gas Storage Facility. The storage facility is located in Assumption Parish, Louisiana and has a total capacity of 8.9 Bcf and is currently in service. This facility is designed for injecting pipeline quality gas into

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•	Louisiana Liquids Pipeline System. The Partnership's Louisiana liquids pipeline system includes approximately 660 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 660 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.

•	Fractionation Facilities. There are four fractionation facilities located in Louisiana that averaged 137,500 Bbls/d for the year ended December 31, 2015.

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Plaquemine Fractionation Facility. The Plaquemine fractionator is located at the Partnership's 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 the Partnership's Riverside facility for further processing. The plant fractionated 59,200 Bbls/d for the year ended December 31, 2015.

•	The Plaquemine Gas Processing Plant. The Plaquemine Gas Processing Plant also has a fractionator with a capacity of 10,800 Bbls/d of raw-make NGL products, and total volume for fractionated liquids at Plaquemine which averaged approximately 2,000 Bbls/d for the year ended December 31, 2015.

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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 49,300 Bbls/d of liquids for the year ended December 31, 2015.

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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 32,000 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 facility has above-ground storage capacity of approximately 278,300 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 27,000 Bbls/d for the year ended December 31, 2015.

•	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 butane service, and space is leased to customers for a fee.

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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 crude oil and condensate rail loading terminal on the Ohio Central Railroad network and approximately 210 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include over 500,000 barrels of above ground storage and a trucking fleet of approximately 86 vehicles comprised of both semi and straight trucks, and 2 newly purchased trailers for hauling NGL volumes with a current capacity of 25,650 Bbls/d. Total crude oil and condensate handled averaged approximately 23,600 Bbls/d for the year ended December 31, 2015. The Partnership has eight existing brine disposal wells with an injection capacity of approximately 4,000 Bbls/d and an average disposal rate of 3,900 Bbls/d for the year ended December 31, 2015. Additionally, the Partnership's ORV operations include eight condensate stabilization and natural gas compression stations with combined capacities of over 36,000 Bbls/d of

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Permian Crude and Condensate. The Partnership's Permian Crude and Condensate assets have crude oil gathering, transportation and marketing operations in the Permian Basin with a current capacity of approximately 71,000 Bbls/d. Its integrated logistics services are supported by 51 tractor trailers, 13 pipeline injection stations and 80 miles of crude oil gathering pipeline. Total crude oil and condensate handled for the period February 1, 2015 to December 31, 2015 averaged approximately 70,900 Bbls/d.

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Victoria Express Pipeline. The VEX pipeline is a 60 mile, multi-grade crude oil pipeline with a current capacity of approximately 90,000 Bbls/d. Other VEX assets include the Cuero Terminal and Port of Victoria Terminal and Barge Docks.  The Cuero truck unloading terminal at the origin of the VEX system contains 8 unloading bays and 200,000 bbls of above-ground storage capacity for receipt from and delivery to the VEX pipeline.  The VEX pipeline terminates at the Port of Victoria Terminal that also has an 8 bay truck unloading dock and 200,000 bbls of above-ground storage capacity.  The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria. Total crude oil and condensate handled averaged approximately 37,400 Bbls/d for the year ended December 31, 2015.

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Gulf Coast Fractionators. The Partnership is entitled to receive the economic benefits and burdens of the 38.75% interest in GCF held by Devon, with the remaining interests owned 22.50% by Phillips 66 and 38.75% by Targa Resources Partners. GCF owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 is the operator of the fractionator. GCF 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 approximately 44,000 Bbls/d of liquids for the year ended December 31, 2015.

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Howard Energy Partners . 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. HEP also owns more than 100 miles of natural gas gathering pipeline in Lycoming and Bradford counties in Pennsylvania and a 230 MBbls/d liquids storage terminal near Port Arthur, Texas. As of December 31, 2015, the Partneship owned a 30.6% interest in HEP and accounted for this investment under the equity method of accounting. Alinda Capital Partners owns a 59% capital interest in HEP.

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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;

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

•	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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neither our operating agreement nor any other agreement requires Devon to pursue a business strategy that favors us, to enter into any commercial agreements with us or the Partnership, or, except as set forth in a first offer agreement pursuant to which Devon is obligated to offer us a right of first offer with respect to its interest in the Access Pipeline transportation system (the “First Offer Agreement”), to sell any assets to us or the Partnership. Devon’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Devon, which may be contrary to our interests;

•	Devon may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

•	Devon, as a major customer of the Partnership, has an economic incentive to cause the Partnership to not seek higher transportation rates and processing fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;

•	the Managing Member determines the amount and timing of asset purchases and sales, borrowings, issuance of additional membership interests and reserves, each of which can affect the amount of cash that is available to be distributed to unitholders;

•	the Managing Member determines which costs incurred by it are reimbursable by us;

•	the Managing Member is allowed to take into account the interests of parties other than us in exercising certain rights under our operating agreement;

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•	our operating agreement limits the liability of, and eliminates and replaces the fiduciary duties that would otherwise be owed by, the Managing Member and also restricts the remedies available to our unitholders for actions that, without the provisions of the operating agreement, might constitute breaches of fiduciary duty;

•	any future contracts between us, on the one hand, and the Managing Member and its affiliates, on the other, will not be the result of arm’s-length negotiations;

•	except in limited circumstances, the Managing Member will have the power and authority to conduct our business without unitholder approval;

•	disputes may arise under commercial agreements between Devon and us or our subsidiaries, including the Partnership;

•	the Managing Member may exercise its right to call and purchase all of our outstanding common units not owned by it and its affiliates if it and its affiliates own more than 90% of our outstanding common units;

•	the Managing Member controls the enforcement of obligations owed to us by the Managing Member and its affiliates, including the commercial agreements and the First Offer Agreement with Devon; and

•	the Managing Member decides whether to retain separate counsel, accountants or others to perform services for us.

•	how to allocate business opportunities among us and its other affiliates;

•	whether to exercise its call right;

•	how to exercise its voting rights with respect to any membership interests it owns;

•	whether or not to consent to any merger or consolidation of us or any amendment to our operating agreement; and

•	whether or not the manager should elect to seek the approval of the conflicts committee or the unitholders, or neither, of any conflicted transaction.

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•	whenever the Managing Member makes a determination or takes, or declines to take, any other action in its capacity as the Managing Member, the Managing Member is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by Delaware law, or any other law, rule or regulation, or at equity;

•	the Managing Member will not have any liability to us or our unitholders for decisions made in its capacity as a managing member so long as it acted in good faith, meaning that it subjectively believed that the decision was in, or not opposed to, our best interests;

•	our operating agreement is governed by Delaware law and any claims, suits, actions or proceedings:

•	arising out of or relating in any way to our operating agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our operating agreement or the duties, obligations or liabilities among members or of members to us, or the rights or powers of, or restrictions on, the members or the company);

•	brought in a derivative manner on our behalf;

•	asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees or the Managing Member, or owed by the Managing Member, to us or our members;

•	asserting a claim arising pursuant to any provision of the DLLCA; or

•	asserting a claim governed by the internal affairs doctrine;

•

must be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing our common units, a member is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings;

•

the Managing Member and its officers and directors will not be liable for monetary damages to us or our members resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Managing Member or its officers or directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

•	the Managing Member will not be in breach of its obligations under our operating agreement or its duties to us or our members if a transaction with an affiliate or the resolution of a conflict of interest is:

•	approved by the conflicts committee of the board of directors of the Managing Member, although the Managing Member is not obligated to seek such approval; or

•	approved by the vote of a majority of our outstanding common units, excluding any common units owned by the Managing Member and its affiliates, although the Managing Member is not obligated to seek such approval.

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•	each unitholder’s proportionate ownership interest in us will decrease;

•	the amount of cash available for distribution on each unit may decrease;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of our common units may decline.

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•	the quarterly distributions paid by us with respect to our common units;

•	our quarterly or annual earnings, or those of other companies in our industry;

•	the loss of Devon as a customer;

•	events affecting Devon;

•	announcements by us or our competitors of significant contracts or acquisitions;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	general economic conditions;

•	the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

•	future sales of our common units; and

•	other factors described in these “Risk Factors.”

•	the requirement that a majority of the board consist of independent directors;

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the requirement that the board of directors have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of equity holders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

•

the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;

•	the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and

•	the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees’ responsibilities and annual performance evaluations.

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

•	the level of the Partnership's processing operations;

•	the fees the Partnership charges and the margins it realizes for its 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 Partnership gathers, compresses, processes, transports and sells, the volume of NGLs the Partnership processes or fractionates and sells, the volume of crude oil the Partnership handles at its crude terminals, the volume of crude oil and condensate the Partnership gathers, transports, purchases and sells, the volumes of condensate stabilized and the volumes of brine the Partnership disposes;

•	the relationship between natural gas and NGL prices; and

•	the Partnership's level of operating costs.

•	the level of capital expenditures the Partnership makes;

•	the cost of acquisitions, if any;

•	the Partnership’s debt service requirements;

•	fluctuations in its working capital needs;

•	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 its respective general partners in its 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;

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•	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 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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•	environmental or other governmental regulations;

•	weather conditions;

•	increases in storage levels of natural gas and NGLs;

•	increased use of alternative energy sources;

•	decreased demand for natural gas and NGLs;

•	continued fluctuations in commodity prices, including the prices of natural gas, NGLs, crude oil and condensate;

•	economic conditions;

•	supply disruptions;

•	availability of supply connected to the Partnership's systems; and

•	availability and adequacy of infrastructure to gather and process supply into and out of the Partnership's systems.

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•	additional or more restrictive covenants that impose operating and financial restrictions on the Partnership and its subsidiaries;

•	the Partnership's subsidiaries to guarantee such debt and certain existing debt, including its senior notes;

•	the Partnership and its subsidiaries to provide collateral to secure such debt; and

•	the Partnership or its subsidiaries to post cash collateral or letters of credit under its hedging arrangements or in order to purchase commodities or obtain trade credit.

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

•	the level of domestic crude 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 crude oil, natural gas and NGLs;

•	international demand for crude oil and NGLs;

•	actions taken by foreign crude oil and gas producing nations;

•	the continued threat of terrorism and the impact of military action and civil unrest;

•	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

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

•	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;

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

•	increase the risk that we may default on our debt obligations.

•	incur subsidiary indebtedness;

•	engage in transactions with its affiliates;

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

•	incur liens;

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•	enter into sale and lease back transactions; and

•	change business activities it conducts.

•	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. Such "ethane rejection," which the Partnership has experienced in greater volumes recently, reduces the volume of NGLs delivered for fractionation and marketing.

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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 Partnership's propane may be reduced during periods of warmer-than-normal weather.

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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.

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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 Partnership's 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;

•	induced seismicity;

•	rail accidents, barge accidents and truck accidents; and

•	fires and explosions.

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•	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;

•	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

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•

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;

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•	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 GP Board exercises its option to do so;

•	capital calls for our interest in Tall Oaks to the extent not covered by our borrowings; and

•	cash reserves the Managing Member believes are prudent to maintain.

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(1)	Includes $141.3 million, $354.3 million, $1,588.2 million, $1,310.3 million, and $1,762.6 million for the year ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively, of affiliate purchased gas.

(2)	Includes $0.5 million, $5.9 million, $36.2 million, $33.8 million, and $34.4 million for the year ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively, of affiliate operating expenses from Devon.

(3)	Includes $0.2 million, $11.6 million, $45.1 million, $41.7 million, and $38.5 million for the year ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively, of affiliate general and administrative expenses from Devon.

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(1)	Represents quarterly distributions paid to us on May 14, 2015, August 14, 2015, November 12, 2015 and distributions declared by ENLK and to be paid to ENLC on February 11, 2016.

(2)	Represents our interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.

(3)	Represents our stand-alone current tax expense.

(4)	Represents our interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA per (2) above.

(1)	Represents quarterly distributions paid to us on May 14, 2015, August 14, 2015, November 12, 2015 and distributions declared by ENLK and to be paid to us on February 11, 2016.

(2)	Represents our stand-alone deferred taxes.

(3)	Represents our interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs, which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA.

(4)	Represents our interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.

(5)	Represents E2's adjusted EBITDA with respect to 2014 and other non-cash items not included in cash available for distributions.

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•	88,528,451 common units representing an aggregate 26.5% limited partner interest in the Partnership; and

•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership ( the “General Partner” ), which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

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•	transporting natural gas and NGLs on the pipeline systems it owns;

•	processing natural gas at its processing plants;

•	fractionating and marketing recovered NGLs;

•	providing compression services;

•	providing crude oil and condensate transportation and terminal services;

•	providing condensate stabilization services; and

•	providing brine disposal services.

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Chisholm Plant. The Chisholm Plant, which serves the STACK play, is a cryogenic gas processing plant with a current capacity of 100 MMcf/d. Depending on future volume requirements, the Chisholm Plant could be expanded by an additional 600 MMcf/d for a total processing capacity of 700 MMcf/d. The plant is connected to a 200-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

•	Battle Ridge Plant. The Battle Ridge Plant, which provides us and the Partnership with an entry into the CNOW play, is a cryogenic gas processing plant with a current capacity of 75 MMcf/d. The plant is connected to a 175-mile, low and high-pressure gathering system with compression facilities. Additional gathering pipelines and compression facilities are currently under construction.

•	Connecting Pipeline. A 42-mile, 16-inch high-pressure header pipeline with a total capacity of 150 MMcf/d was constructed to connect the Chisolm and Battle Ridge Plant systems. The pipeline went into service in February 2016 and provides customers with additional operational flexibility.

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

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

•	Our financial statements for the years ended December 31, 2015 and 2014 report financial results according to operating segments based principally upon geographic regions served.  The Predecessor had no operations for certain of those reporting segments.

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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 impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

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(1)	Volumes include volumes per day based on 365 day period for the years ended December 31, 2015, 2014 and 2013 for the Partnership 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.

(2)	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. Midstream Holdings does not have any operations in Louisiana or Ohio.

(3)	Volumes include volumes per day based on 365 day period for the years ended December 31, 2015, 2014 and 2013 respectively, for Partnership operations. The Partnership did not have any legacy operations in Oklahoma.

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•	$18.8 million is attributable to the legacy Partnership assets for a full year of expenses during 2015 as compared to ten months during 2014;

•	$6.0 million is attributable to certain bonuses paid in March 2015 in the form of unit awards that immediately vested;

•	$5.4 million in transaction costs related to the Partnership's Tall Oak, Matador, LPC, and Coronado asset acquisitions, as well as the VEX dropdown;

•	the Partnership's unit-based compensation expense increased $3.2 million;

•	the Partnership's bad debt expense increased $2.3 million; and

•	the Partnership's salaries and wages increased $5.9 million due to an increase in headcount related to acquisitions during the year.

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

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

•	the Partnership's 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;

•	the Partnership's 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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(1)	Consists of pipeline capacity payments for firm transportation and deficiency agreements.

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

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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 the Partnership.

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1

Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes 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”. The Partnership's 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, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2.

Percent of liquids contracts: Under these contracts, the Partnership receives 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, the Partnership's margins from these contracts are greater during periods of high liquids prices. The Partnership's margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3.

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

4.	Fixed-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.

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*	weighted average

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*	Denotes chairman of committee.

**	Denotes independent director.

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•	the total compensation program, including base salary and bonus opportunities, should be competitive with the market in which we compete for executive talent 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;

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

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

•	base salary;

•	annual bonus awards;

•	long-term incentive plan awards;

•	retirement and health benefits; and

•	severance and change of control 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.

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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.

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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 restricted units for the participant. Under no circumstances will DERs be granted or made with respect to restricted unit awards.

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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.

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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

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Unit Options.  The GP Plan currently permits the grant of options covering common units of the Partnership. These options 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% of the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee and the term of the options cannot exceed ten years from the date of grant. Under no circumstances will distributions or DERs be granted or made with respect to option awards. In addition, the unit options may, pursuant to their terms, become exercisable upon a change of control of us, the Partnership or the General Partner, as discussed below under "-Potential Payments Upon a Change of Control. " Common units to be delivered upon the exercise of a unit option may be common units acquired by the General Partner in the open market, common units already owned

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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 us, 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 DER 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 annual bonus payments. For 2015, all annual bonus payments will be paid in cash. For 2014 and 2013, the named executive officers received bonuses in the form of equity awards that immediately vest. The amounts shown for 2014 and 2013 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.

(2)	The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718. See Note 12 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 $15,900, a 401(k) profit sharing contribution of $6,413, a 401(k) non-discretionary contribution of $5,300, distributions or dividends on restricted units and restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $153,021 in 2015 and distributions on restricted units or restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount $260,108 in 2015.

(5)

Amount of all other compensation for Mr. Steve Hoppe includes professional organization and social club dues, a matching 401(k) contribution of $15,900, a 401(k) profit sharing contribution of $6,413, a 401(k) non-discretionary contribution of $5,300, distributions on restricted units and restricted incentive units and performance units of EnLink Midstream, LLC in the amount of $43,134 in 2015 and distributions on restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount of $76,952 in 2015.

(6)

Amount of all other compensation for Mr. Mac Hummel includes professional organization and social club dues, a matching 401(k) contribution of $15,900, a 401(k) profit sharing contribution of $6,413, a 401(k) non-discretionary contribution of $5,300, moving costs of $68,323, distributions on restricted units and restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $36,406 in 2015 and distributions on restricted incentive units and performance units of EnLink Midstream Partners, LP in the amount of $71,228 in 2015.

(7)

Amount of all other compensation for Mr. Michael Garberding includes professional organization and social club dues, a matching 401(k) contribution of $15,542, a 401(k) profit sharing contribution of $6,413, a 401(k) non-discretionary contribution of $5,300, distributions or dividends on restricted units or restricted incentive units of EnLink Midstream, LLC in the amount of $95,230 in 2015 and distributions on restricted units or restricted incentive units of EnLink Midstream Partners, LP in the amount of $158,809 in 2015.

(8)

Amount of all other compensation for Mr. Benjamin Lamb includes a matching 401(k) contribution of $15,484, a 401(k) profit sharing contribution of $6,413, a 401(k) non-discretionary contribution of $5,300, dividends or distributions on restricted units or restricted incentive units of EnLink Midstream, LLC in the amount of $22,627 in 2015 and distributions on restricted units or restricted incentive units of EnLink Midstream Partners, LP in the amount of $42,590 in 2015.

(9)	Mr. Lamb became a named executive officer in fiscal year 2015, and, therefore, summary compensation information is presented only for fiscal year 2015.

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(1)	These grants vested on March 3, 2015.

(2)	These grants include DERs that provide for distribution on restricted or restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2018.

(3)	These grants vested on January 12, 2015.

(4)	These grants include DERs that provide for distribution on restricted or restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on April 1, 2018.

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(1)	These grants vested on March 3, 2015.

(2)	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 January 1, 2018.

(3)	These grants vested on January 12, 2015.

(4)	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 April 1, 2018.

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(1)	Restricted incentive units vested on January 1, 2016.

(2)	The closing price for the common units was $15.09 as of December 31, 2015.

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

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

(5)	Restricted incentive units vest on July 23, 2017.

(6)	Restricted incentive units vest on January 1, 2018.

(7)	Restricted incentive units vest on April 1, 2018.

(8)

Reflects the target number of performance units granted to the named executive officers on March 17, 2015 multiplied by a performance percentage of 100%, which in accordance with SEC rules is the next higher performance level under the award that exceeds 2015 performance. Vesting of these awards is contingent upon the EnLink TSR performance over the applicable performance period measured against a peer group of companies.

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(1)	Restricted incentive units vested on January 1, 2016.

(2)	The closing price for the common units was $16.58 as of December 31, 2015.

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

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

(5)	Restricted incentive units vest on July 23, 2017.

(6)	Restricted incentive units vest on January 1, 2018.

(7)	Restricted incentive units vest on April 1, 2018.

(8)

Reflects the target number of performance units granted to the named executive officers on March 17, 2015 multiplied by a performance percentage of 100%, which in accordance with SEC rules is the next higher performance level under the award that exceeds 2015 performance. Vesting of these awards is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.

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(1)	Consists of 50,080 units at $35.56 per unit and 11,891 units at $33.64 per unit.

(2)	Consists of 5,202 units at $33.64 per unit.

(3)	Consists of 24,038 units at $35.56 per unit and 7,432 units at $33.64 per unit.

(4)	Consists of 3,079 units at $32.48 per unit and 2,601 units at $33.64 per unit.

(5)	Consists of 38,250 units at $29.01 per unit and 14,920 units at $26.81 per unit.

(6)	Consists of 6,527 units at $26.81 per unit.

(7)	Consists of 18,360 units at $29.01 per unit and 9,325 units at $26.81 per unit.

(8)	Consists of 3,439 units at $29.08 per unit and 3,264 units at $26.81 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, other than Mr. Lamb who is entitled to one times the Severance Benefit, 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), 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 (as defined in the applicable Agreement), or if he terminates employment for good reason (as defined in the applicable Agreement).

(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 Managing Member's 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the Managing Member as earned up to the date of termination if he is terminated for cause (as defined in the applicable Agreement) or he terminates employment without good reason (as defined in the applicable Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(4)

Each named executive officer and one times in the case of Mr. Lamb 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 Change in Control Agreement) or if he terminates employment for good reason (as defined in the Change in Control Agreement) within one-hundred and twenty (120) days prior to or two (2) years following a change in control (as defined in the Control Agreement), subject to compliance with certain non-competition, non-solicitation and other 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.

(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 2015.

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(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 $31.02 per unit and that will vest on March 7, 2016 in the following amounts, respectively: 3,224, 1,612, 3,224 and 1,612. Mr. Echols and Ms. Ricciardello were granted awards of restricted incentive units of EnLink Midstream Partners, LP on March 17, 2015 with a fair market value of $26.72 per unit and that will vest on March 7, 2016 in the following amounts, respectively: 1,871 and 1,871. The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718. See Note 12 to our audited financial statements included in Item 8 herein for the assumptions made in our valuation of such awards. At December 31, 2015, Messrs. Crain, Echols, Galvert and Ms. Ricciardello held aggregate outstanding restricted unit awards, in the following amounts, respectively: 3,224, 1,612, 3,224 and 1,612. At December 31, 2015, Mr. Echols and Ms. Ricciardello held aggregate outstanding restricted incentive units of EnLink Midstream Partnership, LP in the following amounts, respectively: 1,871 and 1,871.

(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 (i) Devon Energy Corporation, whose address is 333 W. Sheridan Avenue, Oklahoma City, Oklahoma 73102, and (ii) Chickasaw Capital Management, LLC, whose address is 6075 Poplar Avenue, Suite 720, Memphis, Tennessee, 38119.

(2)	Devon Gas Services, L.P. (“Devon Gas Services”) is the record holder of 115,495,669 common units. As the indirect owner of 100% of the outstanding limited and general partner interests in Devon Gas Services, Devon Energy Corporation may be deemed to beneficially own all of the common units held by Devon Gas Services.

(3)	1,025,000 of these common units are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(4)	Includes 59,168 common units owned of record by Mr. Crain and 3,224 restricted incentive units that are deemed beneficially owned. 1,000 of these common units are held by the James C. Crain Trust, and Mr. Crain disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(5)	Includes 25,835 common units owned of record by Mr. Echols and 1,612 restricted incentive units that are deemed beneficially owned.

(6)	Includes 1,386 common units owned of record by Ms. Ricciardello and 1,612 restricted incentive units that are deemed beneficially owned.

(7)	Includes 2,772 common units owned of record by Mr. Gafvert and 3,224 restricted incentive units that are deemed beneficially owned.

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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 GP, LLC;

•	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.

(2)

The percentages reflected in the column below are based on a total of 332,270,635 common units, including 7,075,433 Class C common units and 11,228 restricted incentive units that are deemed beneficially owned. The Class C common units were issued to the sellers in connection with our acquisition of Coronado Midstream Holdings LLC on March 16, 2015. Such sellers continue to hold all of the Class C common units, which represent approximately 2.13% of the outstanding common units (including the Class C common units). The Class C common units are substantially similar in all respects to the common units, except that distributions paid on the Class C common units may be paid in cash or in additional Class C common units issued in kind, as determined by our general partner in its sole discretion. The Class C common units will automatically convert into common units on a one-for-one basis on the first business day following the date of the distribution for the quarter ended March 31, 2016.

(3)	The percentages reflected in the column below are based on a total of 382,270,635 common units, which includes the units described in Footnote 2 and 50,000,000 Series B Convertible Preferred units.

(4)	88,652 of these common units are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(5)	Includes 22,638 common units owned of record by Mr. Echols and 1,871 restricted incentive units that are deemed beneficially owned.

(6)	Includes 1,514 common units owned of record by Ms. Ricciardello and 1,871 restricted incentive units that are deemed beneficially owned.

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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 1,148,893 restricted units that have been granted under our long-term incentive plan that have not vested. In addition, the number of securities includes 105,080 performance unit awards granted under the plan, assuming the target distribution at the time of vesting. Actual issuance of these performance unit awards may range from 0% to 200% of the target distribution depending on performance actually attained.

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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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(1)	Includes $141.3 million, $354.3 million and $1,588.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate purchased gas.

(2)	Includes $0.5 million, $5.9 million and $36.2 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate operating expenses from Devon.

(3)	Includes $0.2 million, $11.6 million and $45.1 million for the year ended December 31, 2015, 2014 and 2013, respectively, of affiliate general and administrative expenses from Devon.

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

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•	88,528,451 common units representing an aggregate 26.5% limited partner interest in the Partnership; and

•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

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

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

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**	The VEX amounts reflect the period from February 28, 2014 (the date VEX was acquired by Devon) through December 31, 2014.

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(1)	On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

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(1)	See Note 3-Acquisitions for further discussion.

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(1)	Total distributions- continuing and discontinued operations for the year ended December 31, 2013 of $279.6 million does not include $5.5 million of distributions related to certain assets that weren't transferred to the Partnership, which are included in the Distribution to Predecessor line item on the Consolidated Statements of Changes in Members' Equity.

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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)

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

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(2)

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

(3)

The Partnership's first quarter 2014 distributions on its Class B Common Units of $0.10 per unit were paid on May 14, 2014. Distributions declared for the Class B Common Units represent a pro rata distribution for the number of days the Class B Common Units were issued and outstanding during the quarter. The Class B Common Units automatically converted into common units on a one-for-one basis on May 6, 2014.

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

(1)	The December 31, 2015 and 2014 amount represents a declared distribution of $0.255 per unit payable February 12, 2016, and distributions paid of $0.245 per unit on May 15, 2015, $0.25 per unit on August 14, 2015, $0.255 per unit on November 13, 2015, $0.18 per unit on May 15, 2014, $0.22 per unit on August 13, 2014, $0.23 per unit on November 14, 2014, and $0.235 per unit on on February 13, 2015.

(2)	The 2014 amount includes distribution of $0.05 per unit for Class B Units paid on May 15, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014.

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

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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.

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

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*	Vested units include 95,127 units withheld for payroll taxes paid on behalf of employees.

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*	Amounts consist only of the period from March 7, 2014 through December 31, 2014.

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

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