þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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(1)	Includes the DBM water systems.

(1)	All system metrics are presented on a gross basis and include owned, rented and leased compressors at certain facilities. Includes horsepower associated with liquid pump stations.

(2)	Includes 100% of Chipeta throughput, 50% of Newcastle throughput, 50.1% of Springfield gas gathering throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput.

(3)

Consists of throughput on the Chipeta NGL pipeline, an NGL line at the Brasada complex and at the DBM water systems, a 50.1% share of average Springfield oil gathering throughput, a 10% share of average White Cliffs throughput, a 25% share of average Mont Belvieu JV throughput, a 20% share of average TEG and TEP throughput and a 33.33% share of average FRP throughput. See Properties below for further descriptions of these systems.

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Capitalizing on organic growth opportunities. We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our infrastructure, operating expertise and customer relationships to meet new or increased demand of our services.

•	Increasing third-party volumes to our systems. We continue to actively market our midstream services to, and pursue strategic relationships with, third-party producers and customers with the intention of attracting additional volumes and/or expansion opportunities.

•	Pursuing accretive acquisitions. We expect to continue to pursue accretive acquisitions of midstream assets from Anadarko and third parties.

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Maintaining investment grade metrics. We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that maintain investment grade credit ratings. By maintaining investment grade credit metrics, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance our accretion and overall return.

•	Managing commodity price exposure. We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to a majority of the commodity price uncertainty through the use of fee-based contracts and fixed-price hedges.

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Affiliation with Anadarko. We believe Anadarko is motivated to promote and support the successful execution of our business plan and utilize its relationships within the energy industry and the strength of its asset portfolio to pursue projects that help to enhance the value of our business. This includes the ability of Anadarko to secure equity investment opportunities for us in connection with the commitments it makes to other midstream companies. See Our Relationship with Anadarko Petroleum Corporation below.

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Commodity price and volumetric risk mitigation. We believe our cash flows are protected from fluctuations caused by commodity price volatility due to (i) the approximately 94% of our Adjusted gross margin attributable to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to a majority of our percent-of-proceeds and keep-whole contracts. For the year ended December 31, 2017, 96% of our Adjusted gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. See How We Evaluate Our Operations under Part II, Item 7 of this Form 10-K. On December 20, 2017, we renewed our commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets through December 31, 2018. See Risk Factors under Part I, Item 1A and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. In addition, we mitigate volumetric risk by entering into contracts with cost of service structures and/or minimum volume commitments. For the year ended December 31, 2017, and excluding throughput measured in barrels, 62% of our throughput was subject to demand charges and 14% of our throughput was contracted under a cost of service model.

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Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-term relationships and reasonable access to debt and equity capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of December 31, 2017, we had $825.4 million in available borrowing capacity under the RCF.

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Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, and the Eagleford shale, which have historically seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas serve production where the hydrocarbons contain not only natural gas, but also crude oil, condensate and NGLs.

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Well-positioned and well-maintained assets. We believe that our asset portfolio, which is located in geographically diverse areas of operation, provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio consists of high-quality, well-maintained assets for which we have implemented modern processing, treating, measurement and operating technologies.

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Consistent track record of accretive acquisitions. Since our IPO in 2008, our management team has successfully executed eleven related-party acquisitions and seven third-party acquisitions, with an aggregate acquisition value of $6.3 billion. Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.

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Gathering. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads or production facilities in the area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing, if necessary. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.

•	Stabilization. Stabilization is a process that separates the heavier hydrocarbons (which are also valuable commodities) that are sometimes found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process or by reducing the pressure and letting the more volatile components flash.

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Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

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•	Treating and dehydration. To the extent that gathered natural gas contains water vapor or contaminants, such as carbon dioxide and hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

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Processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and carbon dioxide, sulfur compounds, nitrogen or helium. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in molecular weight, boiling point, vapor pressure and other physical characteristics.

•	Fractionation. Fractionation is the process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.

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Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located throughout the pipeline network or at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.

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Gathering. Crude oil gathering assets provide the link between crude oil production gathered at the well site or nearby collection points and crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries. Crude oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points and deliver into large-diameter trunk lines. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, crude oil can also be trucked from a well site to a central collection point.

•	Stabilization. Crude oil stabilization assets process crude oil to meet vapor pressure specifications. Crude oil delivery points, including crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries, often have specific requirements for vapor pressure and temperature, and for the amount of sediment and water that can be contained in any crude oil delivered to them.

•	Gathering. Produced water often accounts for the largest byproduct stream associated with production of crude oil and natural gas. Produced water gathering assets provide the link between well sites or nearby collection points and disposal facilities.

•	Disposal. As a natural byproduct of crude oil and natural gas production, produced water must be recycled or disposed of in order to maintain production. Produced water disposal systems remove hydrocarbon products and other sediments from the produced water in compliance with applicable regulations and re-inject the produced water utilizing permitted disposal wells.

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Fee-based. Under fee-based arrangements, the service provider typically receives a fee for each unit of (i) natural gas, NGLs, or crude oil gathered, treated, processed and/or transported, or (ii) produced water disposed of, at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.

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Percent-of-proceeds, percent-of-value or percent-of-liquids. Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.

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Keep-whole. Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

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(1)	The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT, which is currently inactive, and Lancaster Trains I and II processing plants; the Platteville amine treating plant; and the Wattenberg gathering system.

(2)	We are the managing member of and own a 75% interest in Chipeta. Chipeta owns the Chipeta processing complex and the Natural Buttes refrigeration plant, which is currently inactive.

•	Customers. As of December 31, 2017, throughput at the DJ Basin complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2017, Anadarko’s production represented 70% of the DJ Basin complex throughput and the largest third-party customer provided 13% of the throughput.

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•	Supply. There were 2,736 active receipt points connected to the DJ Basin complex as of December 31, 2017. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko holds interests in over 400,000 net acres in its core position. Anadarko drilled 348 wells and completed 263 wells during the year ended December 31, 2017.

•	Delivery points. As of December 31, 2017, the DJ Basin complex had the following delivery points for gas not processed within the DJ Basin complex:

◦	Anadarko’s Wattenberg plant inlet; and

◦	Various interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system.

•	Customers. As of December 31, 2017, throughput at the Chipeta complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2017, Anadarko’s production represented 74% of the Chipeta complex throughput and the largest third-party customer provided 15% of the throughput.

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Supply. The Chipeta complex is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko holds interests in 238,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”) and Three Rivers Gathering, LLC’s system, which is owned by Andeavor Logistics LP (“Andeavor”).

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Delivery points. The Chipeta plant delivers NGLs to Enterprise Products Partners LP’s (“Enterprise”) Mid-America Pipeline Company pipeline (“MAPL pipeline”), which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGL fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has residue gas delivery points through the following pipelines delivering to markets throughout the Rockies and Western United States:

◦	CIG pipeline;

◦	Questar pipeline; and

◦	Wyoming Interstate Company’s pipeline (“WIC pipeline”).

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(1)	We have a 14.81% interest in Fort Union and a 50% interest in Newcastle.

(2)	The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.

(3)	The Red Desert complex includes the Red Desert cryogenic processing plant, which is currently inactive, and the Patrick Draw cryogenic processing plant.

(4)	We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.

•	Customers. Throughput at the Bison treating facility was from two third-party customers as of December 31, 2017. The largest customer provided 83% of the throughput for the year ended December 31, 2017. In connection with Anadarko’s sale of its Powder River Basin coal-bed methane assets in 2015, Anadarko retained its throughput commitment to Bison through 2020.

•	Supply and delivery points. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison treating facility is directly connected to Fort Union’s pipeline and the Bison pipeline operated by TransCanada Corporation.

•	Customers. Western Gas Wyoming, L.L.C., Copano Pipelines/Rocky Mountains, LLC, Crestone Powder River LLC and Powder River Midstream, LLC hold a majority of the firm capacity on the Fort Union system. To the extent capacity on the system is not used by these customers, it is available to third parties under interruptible agreements.

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Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the customers noted above and their affiliates throughout the Powder River Basin. The Fort Union customers noted above gather gas for delivery to Fort Union under contracts with acreage dedications from multiple producers in the heart of the basin and from the coal-bed methane producing area near Sheridan, Wyoming.

•	Delivery points. The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:

◦	CIG pipeline;

◦	Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT pipeline”); and

◦	WIC pipeline.

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•	Customers. As of December 31, 2017, gas gathered and processed through the Hilight system was from numerous third-party customers. The three largest producers provided 74% of the system throughput for the year ended December 31, 2017.

•	Supply. The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties, Wyoming.

•	Delivery points. The Hilight plant delivers residue into our MIGC transmission line (see Transportation within these Items 1 and 2). Hilight is not connected to an active NGL pipeline, resulting in all fractionated NGLs being sold locally through truck and rail loading facilities.

•	Customers. Gas gathered and processed through the Newcastle system was from numerous third-party customers as of December 31, 2017. The three largest producers provided 79% of the system throughput, with the largest producer providing 44% of the system throughput, for the year ended December 31, 2017.

•	Supply. The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County, Wyoming. Due to infill drilling and enhanced production techniques, producers have continued to maintain production levels.

•	Delivery points. Propane products from the Newcastle plant are typically sold locally by truck, and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue from the Newcastle system is delivered into Black Hills Corporation’s intrastate pipeline for transport, distribution and sale.

•	Customers. Throughput at the Granger complex was from numerous third-party customers as of December 31, 2017. For the year ended December 31, 2017, 78% of the Granger complex throughput was from two third-party customers.

•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 598 active receipt points as of December 31, 2017.

•	Delivery points. The residue from the Granger complex can be delivered to the following major pipelines:

◦	CIG pipeline;

◦	Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with Andeavor’s Rendezvous pipeline (“Rendezvous pipeline”);

◦	Questar pipeline;

◦	Dominion Energy Overthrust Pipeline;

◦	The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);

◦	our OTTCO pipeline; and

◦	our Mountain Gas Transportation LLC pipeline.

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•	Customers. As of December 31, 2017, throughput at the Red Desert complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2017, 42% of the Red Desert complex throughput was from the two largest third-party customers and 3% was from Anadarko.

•	Supply. The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced from the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.

•	Delivery points. Residue from the Red Desert complex is delivered to the CIG and WIC pipelines, while NGLs are delivered to the MAPL pipeline, as well as to truck and rail loading facilities.

•	Customers. As of December 31, 2017, throughput on the Rendezvous gathering system was primarily from two shippers that have dedicated acreage to the system.

•	Supply and delivery points. The Rendezvous gathering system provides high pressure gathering service for gas from the Jonah and Pinedale Anticline fields and delivers to our Granger plant, as well as Andeavor’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.

(1)	Includes owned, rented and leased compressors and compression horsepower.

(2)	Excludes 1,400 gpm of amine treating capacity at the DBM complex.

(3)	We own a 25% interest in the Mont Belvieu JV, which owns two NGL fractionation trains. A third party serves as the operator.

(4)	We own a 50.1% interest in the Springfield system and serve as the operator.

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•	Customers. As of December 31, 2017, throughput at the Haley system was from Anadarko and two third-party producers. Anadarko’s production represented 88% of the system throughput for the year ended December 31, 2017.

•	Supply. Anadarko holds interests in approximately 590,000 gross (240,000 net) acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.

•	Delivery points. The Haley gathering system provides both lean and rich gas gathering service. The lean service delivery point is into Enterprise GC, L.P.’s pipeline for ultimate delivery into Energy Transfer Partners, LP’s (“ETP”) Oasis pipeline (the “Oasis pipeline”). The rich service delivery point is into a high pressure gathering line, which is part of our DBJV system.

•	Customers. As of December 31, 2017, gas gathered and processed through the DBM complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2017, 67% of the throughput was from the six largest third-party customers and 8% was from Anadarko.

•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko holds interests in approximately 590,000 gross (240,000 net) acres within the Delaware Basin.

•	Delivery points. Residue gas produced at the facility is delivered to the Ramsey Residue Lines, which extend from the DBM complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system (see Transportation within these Items 1 and 2). NGL production is delivered into both the Sand Hills pipeline and Lone Star NGL LLC’s pipeline.

•	Customers. Throughput at the DBJV system was from Anadarko and one third-party producer as of December 31, 2017. Anadarko’s production represented 78% of the system throughput for the year ended December 31, 2017.

•	Supply. The system gathers lean Penn gas, as well as liquids-rich Bone Spring, Avalon and Wolfcamp gas.

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Delivery points. Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to the Bone Spring Gas Processing plant (the “Bone Spring plant”), the Mi Vida Gas Processing plant (the “Mi Vida plant”) and the DBM complex for processing, while lean Penn gas is delivered into Enterprise GC, L.P.’s pipeline. Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline.

•	Customers. As of December 31, 2017, throughput at the DBM water systems was from Anadarko and one third-party producer. Anadarko’s production represented 93% of the throughput for the year ended December 31, 2017.

•	Supply. The systems gather and dispose produced water for Anadarko and a third-party producer.

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•	Customers. The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGL fractionation complex in Mont Belvieu, Texas.

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Supply and delivery points. Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline, TEP and Enterprise’s Panola Pipeline, in which Anadarko has a 15% equity interest. Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.

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•	Customers. Throughput at the Brasada complex was from one third-party customer as of December 31, 2017. In the first quarter of 2017, Anadarko completed the sale of its Eagleford shale upstream assets to a third party.

•	Supply. Supply of gas and NGLs comes from throughput gathered by the Springfield system.

•	Delivery points. The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers stabilized condensate into Plains All American Pipeline and NGLs into the South Texas NGL Pipeline System operated by Enterprise.

•	Customers. Throughput at the Springfield system was from numerous third-party customers as of December 31, 2017. In the first quarter of 2017, Anadarko completed the sale of its Eagleford shale upstream assets to a third party.

•	Supply. Supply of gas and oil comes from third-party production in the Eagleford shale.

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Delivery points. The gas gathering system delivers rich gas to our Brasada complex, the Raptor processing plant owned by Targa Resources Corp. and Sanchez Midstream Partners LP, and to processing plants operated by Enterprise, ETP and Kinder Morgan, Inc. The oil gathering system has delivery points to Plains All American Pipeline, Kinder Morgan, Inc.’s Double Eagle Pipeline, Hilcorp Energy Company’s Harvest Pipeline and NuStar Energy L.P.’s Pipeline.

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(1)	We own a 33.75% interest in the Marcellus Interest gathering systems.

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Customers. As of December 31, 2017, the Marcellus Interest gathering systems had multiple priority shippers. The largest producer provided 75% of the throughput for the year ended December 31, 2017. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC. In the first quarter of 2017, Anadarko completed the sale of its operated and non-operated upstream assets and operated midstream assets (excluding our interests) in the Marcellus shale to a third party.

•	Supply and delivery points. The Marcellus Interest gathering systems are well positioned to serve dry gas production from the Marcellus shale. The Marcellus Interest gathering systems have access to Transcontinental Gas Pipe Line Company, LLC’s pipeline.

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(1)	White Cliffs, GNB NGL, MIGC, FRP, TEP and the Ramsey Residue Lines (at the DBM complex) are regulated by FERC.

(2)	We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.

(3)	We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.

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Customers. The White Cliffs pipeline had multiple committed shippers, including Anadarko, as of December 31, 2017. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. An expansion project was completed in 2017 that increased the pipeline’s capacity from 150 MBbls/d to approximately 180 MBbls/d. The White Cliffs dual pipeline system provides crude oil takeaway capacity from Platteville, Colorado to Cushing, Oklahoma.

•	Supply. The White Cliffs pipeline is supplied by production from the DJ Basin.

•	Delivery points. The White Cliffs pipeline delivery point is SemCrude’s storage facility in Cushing, Oklahoma, a major crude oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries. At the point of origin, it has a 330,000-barrel storage facility adjacent to a truck-unloading facility.

•	Customers. Anadarko was the only shipper on the GNB NGL pipeline as of December 31, 2017.

•	Supply. The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Andeavor’s Stagecoach/Iron Horse gas processing complex.

•	Delivery points. The GNB NGL pipeline delivers NGLs to the MAPL pipeline, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGL fractionation and storage facilities in Mont Belvieu, Texas.

•	Customers. Anadarko was the largest firm shipper on the MIGC system, with 88% of the throughput for the year ended December 31, 2017. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.

•	Supply. MIGC receives gas from various coal-bed methane gathering systems in the Powder River Basin and the Hilight system, as well as from WBI Energy Transmission, Inc. on the north end of the transportation system.

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•	Delivery points. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:

◦	CIG pipeline;

◦	TIGT pipeline; and

◦	WIC pipeline.

•	Customers. For the year ended December 31, 2017, 10% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contracts that contain minimum volume commitments and volumetric fees paid by shippers under firm and interruptible gas transportation agreements.

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Supply and delivery points. Supply points to the OTTCO transportation system include approximately 50 wellheads, the Granger complex and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch and the Jonah and Pinedale Anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities and an inactive interconnection with the Kern River pipeline.

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Front Range Pipeline. FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld County, Colorado (including the Lancaster plant, which is within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2017, FRP had multiple committed shippers, including Anadarko. FRP provides capacity to other shippers at the posted FERC tariff rate.

•	Texas Express Gathering. TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2017.

•	Texas Express Pipeline. TEP delivers to NGL fractionation and storage facilities in Mont Belvieu, Texas. At Skellytown, Texas, TEP is supplied with NGLs from other pipelines including FRP and the MAPL pipeline. As of December 31, 2017, TEP had multiple committed shippers, including Anadarko. TEP provides capacity to other shippers at the posted FERC tariff rates.

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Mentone processing plant: We are currently constructing two cryogenic processing trains at a new processing plant located in Loving County, Texas. Mentone Trains I and II will each have a capacity of 200 MMcf/d and we expect these trains to be completed during the third and fourth quarters of 2018, respectively. The Mentone processing plant will be part of the DBM complex, and upon completion of Mentone Trains I and II, the DBM complex will have a total processing capacity of 1,300 MMcf/d.

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Latham processing plant: We have sanctioned two cryogenic processing trains at a new processing plant located in Weld County, Colorado. Construction of Latham Trains I and II (each with a capacity of 200 MMcf/d) is expected to begin by the third quarter of 2018 and we expect these trains to be completed during the first and third quarters of 2019, respectively. The Latham processing plant will be part of the DJ Basin complex, and upon completion of Latham Trains I and II, the DJ Basin complex will have a total processing capacity of 1,250 MMcf/d.

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

•	types of services that may be offered to customers;

•	certification and construction of new facilities;

•	acquisition, extension, disposition or abandonment of facilities;

•	maintenance of accounts and records;

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

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

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

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

•	initiation and discontinuation of services;

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

•	participation by interstate pipelines in cash management arrangements.

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•	the Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements, and which the U.S. Environmental Protection Agency (the “EPA”) has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;

•	the Federal Water Pollution Control Act, also known as the Federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemakings as protected waters of the United States;

•	the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities and pipelines to liability for removal costs and damages arising from an oil spill in waters of the United States;

•	the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•	the Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

•	the Safe Drinking Water Act, which regulates the quality of the nation’s public drinking water through adoption of drinking water standards and control over the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

•	the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;

•	the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

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•	the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment; and

•	U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency preparedness.

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•	our ability to pay distributions to our unitholders;

•	our and Anadarko’s assumptions about the energy market;

•	future throughput (including Anadarko production) which is gathered or processed by or transported through our assets;

•	our operating results;

•	competitive conditions;

•	technology;

•	the availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;

•	the supply of, demand for, and price of, oil, natural gas, NGLs and related products or services;

•	our ability to mitigate exposure to the commodity price risks inherent in our percent-of-proceeds and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;

•	weather and natural disasters;

•	inflation;

•	the availability of goods and services;

•	general economic conditions, internationally, domestically or in the jurisdictions in which we are doing business;

•	federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;

•	environmental liabilities;

•	legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;

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•	changes in the financial or operational condition of Anadarko;

•	the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners, and other parties;

•	changes in Anadarko’s capital program, strategy or desired areas of focus;

•	our commitments to capital projects;

•	our ability to use the RCF;

•	our ability to repay debt;

•	conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;

•	our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

•	our ability to acquire assets on acceptable terms from Anadarko or third parties, and Anadarko’s ability to generate an inventory of assets suitable for acquisition;

•	non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing, transportation and disposal agreements and our $260.0 million note receivable from Anadarko;

•	the timing, amount and terms of future issuances of equity and debt securities;

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the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (“NTSB”) related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarko and we comply with regulatory orders or other state or local changes in laws or regulations in Colorado; and

•	other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Estimates included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.

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•	the volatility of oil and natural gas prices, which could have a negative effect on the value of Anadarko’s oil and natural gas properties, its drilling programs and its ability to finance its operations;

•	the availability of capital on favorable terms to fund Anadarko’s exploration and development activities;

•	a reduction in or reallocation of Anadarko’s capital budget, which could reduce the gathering, transportation and treating volumes available to us as a midstream operator, limit our midstream opportunities for organic growth or limit the inventory of midstream assets we may acquire from Anadarko;

•	Anadarko’s ability to replace its oil and natural gas reserves;

•	Anadarko’s operations in foreign countries, which are subject to political, economic and other uncertainties;

•	Anadarko’s drilling, flowline, pipeline, and operating risks, including potential environmental liabilities;

•	transportation capacity constraints and interruptions;

•	adverse effects of governmental and environmental regulation;

•	shareholder activism with respect to Anadarko’s stock or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas by Anadarko; and

•	adverse effects from current or future litigation.

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•	domestic and worldwide economic and geopolitical conditions;

•	weather conditions and seasonal trends;

•	the ability to develop recently discovered fields or deploy new technologies to existing fields;

•	the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;

•	the availability of imported, or a market for exported, liquefied natural gas;

•	the availability of transportation systems with adequate capacity;

•	the volatility and uncertainty of regional pricing differentials, such as in the Rocky Mountains;

•	the price and availability of alternative fuels;

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•	the effect of energy conservation measures;

•	the nature and extent of governmental regulation and taxation; and

•	the forecasted supply and demand for, and prices of, oil, natural gas, NGLs and other commodities.

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•	the prices of, level of production of, and demand for oil and natural gas;

•	the volume of oil and natural gas we gather, compress, process, treat and/or transport;

•	the volumes and prices of NGLs and condensate that we retain and sell;

•	demand charges and volumetric fees associated with our transportation services;

•	the level of competition from other midstream companies;

•	regulatory action affecting the supply of or demand for oil or natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and

•	prevailing economic conditions.

•	our level of capital expenditures;

•	our level of operating and maintenance and general and administrative costs;

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

•	our treatment as a flow-through entity for U.S. federal income tax purposes;

•	restrictions contained in debt agreements to which we are a party; and

•	the amount of cash reserves established by our general partner.

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•	mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;

•	an inability to successfully integrate the acquired assets or businesses;

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

•	mistaken assumptions about the overall costs of equity or debt;

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

•	unforeseen difficulties operating in new geographic areas; and

•	customer or key employee losses at the acquired businesses.

•	incur additional indebtedness or guarantee other indebtedness;

•	grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;

•	engage in transactions with affiliates;

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•	make any material change to the nature of our business from the midstream business; or

•	enter into a merger, consolidate, liquidate, wind up or dissolve.

•	our 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;

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

•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our flexibility in responding to changing business and economic conditions may be limited.

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Ground-Level Ozone Standards. In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion. The EPA published a final rule in November 2017 that issued attainment or unclassifiable area designations with respect to ground-level ozone for numerous counties in the United States and is expected to issue non-attainment area designations in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states with counties that are designated as non-attainment are expected to implement more stringent regulations for those non-attainment areas, which could require installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

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Reduction of Methane Emissions by the Oil and Gas Industry. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards, known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards to, among other things, hydraulically fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants and pneumatic pumps. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years and revisit the entirety of the 2016 standard, but it has not yet published a final rule and, as a result, the June 2016 standards remain in effect but future implementation of the 2016 standards is uncertain at this time. Furthermore, the Bureau of Land Management (“BLM”) published a final rule in November 2016 that requires a reduction in methane emissions from venting, flaring and leaking on public lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged by several non-governmental organizations and states. Notwithstanding the current uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural gas exploration and production operators, to reduce methane emissions. At the state level, some states where we operate, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural gas sources. Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and significantly increase our capital expenditures and operating costs.

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Reduction of GHG Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France and agreed to review its GHG emissions and set GHG emission reduction goals every five years beginning in 2020. Although this agreement does not create any binding obligations, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement, which would result in an effective exit date of November 2020. Notwithstanding any withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where we conduct operations could adversely affect demand for oil and natural gas.

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

•	inadvertent damage from construction, farm and utility equipment;

•	leaks or losses of hydrocarbons or produced water as a result of the malfunction of equipment or facilities;

•	fires and explosions (for example, see Items Affecting the Comparability of Our Financial Results, under Part II, Item 7 of this Form 10-K for a discussion of the incident at the DBM complex); and

•	other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or curtailment or suspension of operations.

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•	Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.

•	Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.

•	Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.

•	The officers of our general partner devote significant time to the business of Anadarko and are compensated by Anadarko accordingly. For example, all of the equity incentive compensation currently provided to the officers of our general partner is tied to Anadarko’s common stock rather than our or WGP’s common units.

•	Our partnership agreement limits the liability of, and reduces the default state law fiduciary duties owed by, our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

•	Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner.

•	Our general partner determines which costs incurred by it are reimbursable by us.

•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make IDR payments.

•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner has limited, and intends to continue to limit, its liability regarding our contractual and other obligations.

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•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the Special Committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

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•	how to allocate corporate opportunities among us and its affiliates;

•	whether to exercise its limited call right;

•	how to exercise its voting rights with respect to the units it owns;

•	whether to exercise its registration rights;

•	whether to elect to reset target distribution levels; and

•	whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner 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 our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;

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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees 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 our general partner or its officers and 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 criminal; and

•	provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:

(a)	approved by the Special Committee of the Board of Directors, although our general partner is not obligated to seek such approval;

(b)	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

(c)	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d)	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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•	our existing unitholders’ proportionate ownership interest in us will decrease;

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

•	the ratio of taxable income to distributions may increase;

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

•	the market price of the common units may decline.

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•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

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•	changes in investor or analyst estimates of Anadarko’s and our financial performance or our future distribution growth;

•	the public’s reaction to Anadarko’s or our press releases, announcements and filings with the SEC;

•	legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;

•	fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;

•	changes in market valuations of similar companies;

•	departures of key personnel;

•	commencement of or involvement in litigation;

•	variations in our quarterly results of operations or those of other midstream companies;

•	variations in the amount of our quarterly cash distributions;

•	future issuances and sales of our common units; and

•	changes in general conditions in the U.S. economy, financial markets or the midstream industry.

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(1)	See Property exchange below.

(2)	Acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP.

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(1)	Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations under Part II, Item 7 of this Form 10-K.

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(1)	Includes the DBM water systems.

•	In March 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, resulting in a net gain of $125.7 million. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

•	In May 2017, we reached an agreement with Anadarko to settle the outstanding Deferred purchase price obligation - Anadarko, arising from our acquisition of DBJV, whereby we made a cash payment to Anadarko of $37.3 million during the second quarter of 2017.

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•	On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis. See Equity Offerings under Part I, Items 1 and 2 of this Form 10-K for additional information.

•	We commenced operation of the DBM water systems in the second quarter of 2017 and Train VI at the DBM complex (with capacity of 200 MMcf/d) in the fourth quarter of 2017.

•	In June 2017, we closed on the sale of our Helper and Clawson systems, which resulted in a net gain on divestiture of $16.3 million. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

•	In February 2017, Anadarko elected to extend the conversion date of the Class C units from December 31, 2017, to March 1, 2020.

•	We received $52.9 million in cash proceeds from insurers in final settlement of our claims related to the incident at the DBM complex, including $29.9 million for business interruption insurance claims and $23.0 million for property insurance claims. See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information.

•	We raised our distribution to $0.920 per unit for the fourth quarter of 2017, representing a 2% increase over the distribution for the third quarter of 2017 and a 7% increase over the distribution for the fourth quarter of 2016.

•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,575 MMcf/d for the year ended December 31, 2017, representing a 9% decrease compared to the year ended December 31, 2016.

•	Throughput for crude oil, NGL and produced water assets totaled 201 MBbls/d for the year ended December 31, 2017, representing a 9% increase compared to the year ended December 31, 2016.

•	Operating income (loss) was $707.3 million for the year ended December 31, 2017, which was approximately the same as for the year ended December 31, 2016.

•	Adjusted gross margin for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $0.94 per Mcf for the year ended December 31, 2017, representing a 13% increase compared to the year ended December 31, 2016.

•	Adjusted gross margin for crude oil, NGL and produced water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $2.10 per Bbl for the year ended December 31, 2017, which was approximately the same as for the year ended December 31, 2016.

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•	expenses associated with annual and quarterly reporting;

•	tax return and Schedule K-1 preparation and distribution expenses;

•	expenses associated with listing on the NYSE; and

•	independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.

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•	our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure or historical cost basis;

•	the ability of our assets to generate cash flow to make distributions; and

•	the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

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(1)	Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. Other expense also includes $0.1 million, $0.2 million and $0.4 million of lower of cost or market inventory adjustments, primarily at the DBM complex for the years ended December 31, 2017, 2016 and 2015, respectively.

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(1)	Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2)	Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex. Other expense also includes $0.1 million, $0.2 million and $0.4 million of lower of cost or market inventory adjustments, primarily at the DBM complex for the years ended December 31, 2017, 2016 and 2015, respectively.

(3)	See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)	Reflects cash distributions of $3.590 per unit declared for the year ended December 31, 2017, including the cash distribution of $0.920 per unit paid on February 13, 2018, for the fourth-quarter 2017 distribution.

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•	DBJV acquisition. In March 2015, we acquired Anadarko’s interest in DBJV for an anticipated cash payment of $282.8 million due to Anadarko on March 31, 2020. In May 2017, we reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

•	Dew and Pinnacle divestiture. In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party, resulting in a net gain on sale of $77.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

•	Hugoton divestiture. In October 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of $12.0 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

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Property exchange. On March 17, 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. We previously held a 50% interest in, and operated, the DBJV system. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.

•	Helper and Clawson divestiture. In June 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

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(1)

Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2)	See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(3)	Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 7. For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations–Reconciliation of non-GAAP measures within this Item 7.

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(1)	Represents our 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput.

(2)	Represents our 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, and 33.33% share of average FRP throughput.

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(1)

Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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(1)

Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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(1)	See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a discussion of the Deferred purchase price obligation - Anadarko.

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(1)

Adjusted gross margin for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin for natural gas assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation of non-GAAP measures within this Item 7.

(2)

Adjusted gross margin for crude oil, NGL and produced water assets is calculated as total revenues and other for crude oil, NGL and produced water assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude oil, NGL and produced water assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude oil, NGL and produced water assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation of non-GAAP measures within this Item 7.

(3)	For a reconciliation of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation of non-GAAP measures within this Item 7.

(4)	Average for period. Calculated as Adjusted gross margin for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.

(5)	Average for period. Calculated as Adjusted gross margin for crude oil, NGL and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGL and produced water assets.

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maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows; or

•	expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those expenditures incurred to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.

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(1)	Capital expenditures for the years ended December 31, 2017, 2016 and 2015, are presented net of $1.4 million, $6.1 million and $0.5 million, respectively, of contributions in aid of construction costs from affiliates.

(2)	For the years ended December 31, 2017, 2016 and 2015, included $6.8 million, $5.6 million and $8.3 million, respectively, of capitalized interest.

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•	$673.6 million of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBJV system and the DBM and DJ Basin complexes and the construction of the DBM water systems;

•	$155.3 million of cash consideration paid as part of the Property Exchange;

•	$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;

•	$23.1 million of distributions from equity investments in excess of cumulative earnings;

•	$23.0 million of proceeds from property insurance claims attributable to the DBM outage; and

•	$3.9 million of cash paid for equipment purchases from Anadarko.

•	$712.5 million of cash paid for the acquisition of Springfield;

•	$473.9 million of capital expenditures, net of $6.1 million of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM and DJ Basin complexes and the DBJV system;

•	$45.1 million of net proceeds from the sale of the Hugoton system in Southwest Kansas and Oklahoma;

•	$21.2 million of distributions from equity investments in excess of cumulative earnings;

•	$17.5 million of proceeds from property insurance claims attributable to the DBM outage; and

•	$4.0 million of cash paid for equipment purchases from Anadarko.

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•	$637.5 million of capital expenditures, net of $0.5 million of contributions in aid of construction costs from affiliates, primarily related to the construction of Train IV at the DBM complex, continued construction of Lancaster Train II (within the DJ Basin complex) and expansion at the DBJV system;

•	$145.6 million of net proceeds from the sale of the Dew and Pinnacle systems in East Texas;

•	$16.2 million of distributions from equity investments in excess of cumulative earnings;

•	$11.4 million of cash contributed to equity investments, primarily related to expansion projects at White Cliffs, TEP and FRP;

•	$10.9 million of cash paid for equipment purchases from Anadarko; and

•	$3.5 million of cash paid for post-closing purchase price adjustments related to the DBM acquisition.

•	$801.3 million of distributions paid to our unitholders;

•	$370.0 million of borrowings under the RCF, which were used for general partnership purposes, including funding of capital expenditures;

•	$58.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;

•	$37.3 million of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko; and

•	$13.6 million of distributions paid to the noncontrolling interest owner of Chipeta.

•	$900.0 million of repayments of outstanding borrowings under the RCF;

•	$671.9 million of distributions paid to our unitholders;

•	$599.3 million of borrowings under the RCF, net of extension costs, which were used to fund a portion of the Springfield acquisition and for general partnership purposes, including funding capital expenditures;

•	$494.6 million of net proceeds from the 2026 Notes offering in July 2016, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under the RCF;

•	$440.0 million of net proceeds from the issuance of 14,030,611 Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;

•	$246.9 million of net proceeds from the issuance of 7,892,220 Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under the RCF in connection with the acquisition of Springfield;

•	$203.3 million of net proceeds from the offering of the additional 2044 Notes in October 2016, after underwriting discounts and original issue premium and offering costs, all of which was used to repay amounts then outstanding under the RCF and for general partnership purposes, including capital expenditures;

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•	$45.8 million of capital contributions from Anadarko related to the above-market component of swap agreements;

•	$25.0 million of net proceeds from the sale of common units to WGP, all of which was used to fund a portion of the acquisition of Springfield;

•	$23.5 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield; and

•	$13.8 million of distributions paid to the noncontrolling interest owner of Chipeta.

•	$610.0 million of repayments of outstanding borrowings under the RCF;

•	$545.1 million of distributions paid to our unitholders;

•	$489.6 million of net proceeds from the 2025 Notes offering in June 2015, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under the RCF;

•	$400.0 million of borrowings under the RCF, which were used for general partnership purposes, including funding capital expenditures;

•	$57.4 million of net proceeds from sales of common units under the registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of our common units. Net proceeds were used for general partnership purposes, including funding capital expenditures;

•	$49.8 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield and DBJV;

•	$18.4 million of capital contribution from Anadarko related to the above-market component of swap agreements; and

•	$12.2 million of distributions paid to the noncontrolling interest owner of Chipeta.

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•	significant changes in our unit price;

•	significant declines in commodity prices;

•	significant increases in operating and capital costs;

•	impairments recognized;

•	acquisitions and disposals of assets;

•	changes in throughput; and

•	significant declines in trading multiples for our peers.

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(1)

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $86.0 million, $80.5 million and $167.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Operation and maintenance includes charges from Anadarko of $72.5 million, $72.3 million and $77.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. General and administrative includes charges from Anadarko of $39.1 million, $38.1 million and $33.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. See Note 5.

(2)	Includes losses related to an incident at the DBM complex for the years ended December 31, 2017 and 2015. See Note 1.

(3)	Includes affiliate (as defined in Note 1) amounts of $(0.1) million, $7.7 million and $(14.4) million for the years ended December 31, 2017, 2016 and 2015, respectively. See Note 2 and Note 12.

(4)	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4.

(5)	See Note 4 for the calculation of net income (loss) per common unit.

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(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $36.3 million and $76.6 million as of December 31, 2017 and 2016, respectively. Accounts receivable, net as of December 31, 2016, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.

(2)	Accounts and imbalance payables includes affiliate amounts of $0.3 million and zero as of December 31, 2017 and 2016, respectively.

(3)	Accrued liabilities includes affiliate amounts of $0.2 million and zero as of December 31, 2017 and 2016, respectively.

(4)	See Note 2.

(5)	The Series A Preferred units converted into common units on a one-for-one basis in 2017. See Note 4.

(6)	The Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 4.

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(1)	See Note 5.

(2)	See Note 2.

(3)	See Note 4.

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(1)	Includes losses related to an incident at the DBM complex for the years ended December 31, 2017 and 2015. See Note 1.

(2)	See Note 2.

(3)	See Note 5.

(4)	Includes $(1.4) million related to pipe and equipment purchases and $(1.8) million related to other assets for the year ended December 31, 2017. See Note 5.

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(1)	Includes the DBM water systems.

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(1)	Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

(2)	The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

(3)	The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

(4)	The Partnership acquired an additional 50% interest in the DBJV system (the “Additional DBJV System Interest”) from a third party on March 17, 2017. See Note 2.

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•

Fee-based gathering / processing. Under Topic 605, fee revenue was recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, certain contingent fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, the Partnership will recognize revenue associated with upfront or limited-term fees over the expected period of benefit. In addition, the contingent fees will be estimated and recognized as the services are performed for the customer’s delivered volumes. Differences between revenue recognized and amounts billed to customers will be recognized as contract assets or contract liabilities as appropriate. This will result in a change in the timing of revenue and changes to net income as a result of the consideration provisions. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts.

•

Cost of service rate adjustments. The Partnership receives fee revenue from contracts that require periodic rate redeterminations based upon the Partnership’s costs of service. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Management is continuing to evaluate the proper accounting for these cost of service-based rate changes under Topic 606. The final conclusion about the accounting for these rate redeterminations could impact the cumulative effect adjustment that will be recorded effective January 1, 2018.

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Aid in construction. Under certain midstream service contracts, the Partnership receives reimbursement for capital costs necessary to provide services to the customer (i.e., connection costs, etc.). These reimbursements historically have been reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Beginning in 2018, reimbursement of capital costs received from customers will be reflected as a contract liability (deferred revenue) upon receipt. The contract liability will be amortized to revenue over the expected period of benefit. The magnitude of this change to net income and to the Partnership’s capital expenditures is dependent on the amount of aid in construction reimbursements received from customers.

•

Percentage of proceeds - gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provided midstream services and recognized revenue when the product was sold to a third party. Under Topic 606, in some instances where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions will be presented net within revenue because the Partnership is acting as the producer’s agent in the sale. While reported product sales revenue and expense will be materially reduced, these presentation changes will not impact net income. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes.

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Noncash consideration - keep-whole and percentage of product agreements. The Partnership receives noncash consideration in the form of gas and/or NGL products in exchange for services under certain midstream contracts. Under Topic 605, the Partnership recognized revenue only upon the sale of the related products. Under Topic 606, the Partnership will recognize revenue for the products received as noncash consideration in exchange for the services provided to the customer, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas. The Partnership will also recognize both revenue and cost of product expense upon sale of the related products to a different customer. Reported revenue and expense are not expected to be materially impacted by this change, and there will be no impact to net income. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes.

•

Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenue. Under Topic 606, the fees charged to the contract counterparty are recognized as adjustments to the purchase cost instead of revenue when such fees relate to services performed after control of the product transfers to the Partnership. While there is no impact to net income, it will result in decreased revenue and cost of product expense. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts.

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(1)

The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. At the time of acquisition, DBJV owned a 50% interest in a gathering system and related facilities (the “DBJV system”) located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the estimated net present value of which was $174.3 million. For further information, see DBJV acquisition—deferred purchase price obligation - Anadarko below.

(2)

The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system. The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units.

(3)	The Partnership acquired the Additional DBJV System Interest from a third party. See Property exchange below.

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(1)	Calculated using Level 3 inputs.

(2)	Financing-related accretion revisions were recorded in Interest expense in the consolidated statements of operations.

(3)	Recorded as revisions within Common units in the consolidated balance sheets and consolidated statements of equity and partners’ capital.

(4)	Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations.

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(1)

The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2017 of $0.920 per unit, or $216.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 13, 2018, to unitholders of record at the close of business on February 1, 2018.

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(1)	Quarterly per unit distribution prorated for the 18-day period during which 14,030,611 Series A Preferred units were outstanding during the first quarter of 2016.

(2)	Full quarterly per unit distribution on 14,030,611 Series A Preferred units and quarterly per unit distribution prorated for the 77-day period during which 7,892,220 Series A Preferred units were outstanding during the second quarter of 2016.

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(1)	Adjusted to reflect amortization of the beneficial conversion features.

(2)	The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for all periods presented. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

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(1)	Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded.

(2)	Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded.

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(1)	Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015, December 1, 2016, and December 20, 2017, for the 2015 Market Prices, 2016 Market Prices, 2017 Market Prices, and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

(2)	The Hugoton system was sold in October 2016. See Note 2.

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(1)	Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)	Represents expenses incurred on and subsequent to the date of the acquisition of Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.

(3)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).

(4)	Represents interest income recognized on the note receivable from Anadarko.

(5)	Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12).

(6)	Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 2).

(7)	Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2).

(8)	Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

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(1)	Includes a reduction of $2.2 million in deferred state income taxes for the year ended December 31, 2015. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25%. The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted.

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(1)

The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.

(2)

The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

(3)

The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.

(4)

The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

(5)

The Partnership has a 20% interest in TEG, which owns two NGL gathering systems that link natural gas processing plants to TEP. Midcoast Energy Partners, L.P., a wholly-owned subsidiary of Enbridge, Inc., is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

(6)

The Partnership has a 20% interest in TEP, which owns an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

(7)

The Partnership has a 33.33% interest in FRP, which owns an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

(8)	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual investment basis.

(9)	Recorded in Impairments in the consolidated statements of operations.

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(1)	Fair value is measured using the market approach and Level 2 inputs.

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(1)	See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko.

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(1)	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets.

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•	base salary;

•	annual cash incentives;

•	equity-based compensation, which includes equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan (the “Omnibus Plan”); and

•	certain other Anadarko benefits that are provided on the same basis to other eligible Anadarko employees, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits.

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•	retirement benefits to match competitive practices in Anadarko’s industry, including participation in Anadarko’s employee savings plan, savings restoration plan, retirement plan and retirement restoration plan;

•	severance benefits under the Anadarko Officer Severance Plan;

•	certain change of control benefits under key employee change of control contracts;

•	director and officer indemnification agreements;

•	a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, voluntary participation in the Deferred Compensation Plan, and personal excess liability insurance; and

•	certain benefits that are also provided to all other eligible U.S.-based Anadarko employees, including medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance and disability coverage.

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(1)	The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the years ended December 31, 2017, 2016 and 2015. Mr. Sinclair’s amount reflects base salary compensation earned and allocated through February 12, 2017. Mr. Casas’ amount reflects base salary compensation earned and allocated since joining the Partnership on May 22, 2017.

(2)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the 2012 Anadarko Omnibus Incentive Compensation Plans and include unvested amounts. For a discussion of valuation assumptions for the awards under the 2012 Anadarko Omnibus Incentive Compensation Plans, see Note 22—Share-Based Compensation in the Notes to Consolidated Financial Statements included under Part II, Item 8 of Anadarko’s Form 10-K for the year ended December 31, 2017 (which is not, and shall not be deemed to be, incorporated by reference herein). For information regarding the non-option stock awards granted to the named executives in 2017, see the Grants of Plan-Based Awards Table. The amounts in this column also reflect the allocation of Anadarko performance unit awards, where such gross amounts are subject to market conditions and have been valued based on the probable outcome of the market conditions as of the grant date.

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(3)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the 2012 Anadarko Omnibus Incentive Compensation Plans. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in 2017, see the Grants of Plan-Based Awards Table.

(4)

The amounts in this column reflect the compensation under the Anadarko annual incentive program expected to be allocated to us for the year ended December 31, 2017, and allocated to us for the years ended December 31, 2016 and 2015. Given the timing of when payments are to be made in 2018, the 2017 amounts represent payments which were earned in 2017 and are expected to be paid in early 2018, with an assumed at-target payout, which may not be indicative of the payout our named executive officers will actually receive. The 2016 amounts represent payments which were earned in 2016 and paid in early 2017 and the 2015 amounts represent the payments which were earned in 2015 and paid in early 2016. For an explanation of the 2017 annual incentive plan awards, read Compensation Discussion and Analysis – Analysis of 2017 Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses), contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 5, 2018.

(5)	The amounts in this column reflect the compensation expenses related to Anadarko’s retirement and savings plans that were allocated to us for the years ended December 31, 2017, 2016 and 2015. Mr. Sinclair’s amounts reflect allocated expenses through February 12, 2017. The 2017 allocated expenses are detailed in the table below:

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(1)

Reflects the estimated 2017 cash payouts allocable to us under Anadarko’s annual incentive plan. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us consistent with the methodologies set forth in the services and secondment agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2017 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan, read Compensation Discussion and Analysis — Analysis of 2017 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 5, 2018.

(2)

Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in 2017. Under the performance unit program, participants may earn from 0% to 200% of the targeted award based on Anadarko’s relative total shareholder return performance over a three-year performance period. If earned, the awards are to be paid in cash rather than equity. The threshold value represents the minimum payment (other than zero) that may be earned. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received performance unit awards earlier in the year as a result of their respective promotions. For additional discussion of Anadarko’s performance unit awards, read Compensation Discussion and Analysis — Analysis of 2017 Compensation Actions — Equity Compensation contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 5, 2018.

(3)

Reflects the allocable number of restricted stock shares and restricted stock units awarded in 2017 under the Omnibus Plan. Generally speaking, these awards vest ratably over three years, beginning with the first anniversary of the grant date. For restricted stock shares, dividends are paid at the same time as dividends are paid with respect to outstanding shares of Anadarko common stock. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received restricted stock unit awards with three year vesting schedules earlier in the year as a result of their respective promotions, and Mr. Casas received restricted stock unit awards with a four year vesting schedule upon his hire. Also included are the 10,406 allocated special restricted stock units awarded in 2017 under the Omnibus Plan to each of Messrs. Collins and Peacock, which will vest in four years from grant date, provided Messrs. Collins and Peacock remain employed by Anadarko until such date.

(4)

Reflects the allocable number of Anadarko stock options each named executive officer was awarded in 2017. These awards vest ratably over three years, beginning with the first anniversary of the date of grant and have a term of seven years. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received Anadarko stock options with three year vesting schedules earlier in the year as a result of their respective promotions, and Mr. Casas received options with a four year vesting schedule upon his hire.

(5)

The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in 2017 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 22—Share-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of Anadarko’s Form 10-K for the year ended December 31, 2017 (which is not, and shall not be deemed to be, incorporated by reference herein).

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(1)	Stock options have a seven-year term and will vest ratably over three years in equal installments on the first, second, and third anniversaries of the date of grant. Stock option awards do not accrue dividends or dividend equivalents.

(2)

Generally speaking, the restricted stock units and shares will vest pro-rata annually over three years, beginning with the first anniversary of the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are settled in shares of unrestricted common stock, less applicable withholding taxes. For restricted stock shares, dividends are paid at the same time as dividends are paid with respect to outstanding shares of Anadarko common stock. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. The 14,547 allocated special restricted stock units received in November 2016 by Mr. Fink, and the 10,406 allocated special restricted stock units received in November 2017 by each of Messrs. Collins and Peacock, as well as the corresponding dividend unit equivalents, will vest in four years from the grant date, provided Messrs. Fink, Collins and Peacock remain employed by Anadarko until such dates.

(3)

The number of outstanding units and the estimated payout percentages disclosed for each award are calculated based on Anadarko’s relative performance ranking as of December 31, 2017, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. Anadarko’s relative performance rankings as of December 31, 2017 were: 0% for the 2014 grant, 40% for the 2015 grant, 40% for the 2016 grant and 40% for the February and March 2017 grant. For awards granted in November 2017 with a performance period beginning in 2018, target payout has been assumed.

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(1)	Shares acquired and values realized on exercise include options exercised in 2017. The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise.

(2)

Shares acquired and values realized on vesting reflect the taxable value to the named executive officer as of the date of the vesting in 2017 of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.

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(1)

Under the terms of the 2015 performance unit agreement, retirement-eligible participants, as defined by the Anadarko Petroleum Corporation Retiree Health Benefits Plan, receive a prorated payout, paid after the end of the performance period, based on actual performance and the number of months worked during the performance period. Additionally, the performance unit agreements for awards granted on or after November 10, 2016 provide for payout at the end of the performance period, with no proration and based on actual performance, in cases of a qualified retirement, or retirement at or after age 60 with minimum 10 years of service. As of December 31, 2017, none of our named executive officers were eligible for retirement nor qualified retirement.

(2)

Under the terms of the restricted stock unit agreements effective on or after November 10, 2016, in the event of a qualified retirement, or retirement at or after age 60 with minimum 10 years of service, restricted stock units that are held for at least 180 days after grant date will be settled according to the vesting schedule. As of December 31, 2017, none of our named executive officers were eligible for qualified retirement.

(1)	The values assume two times base salary plus one times target bonus multiplied by the applicable named executive officer’s allocation percentages in effect as of December 31, 2017.

(2)

Payment, if provided, will be paid at the end of the performance period based on actual performance. The values reflect the allocated portion of our named executive officer’s assumed at-target bonus awarded under the annual incentive plan. For additional discussion of this program, read Compensation Discussion and Analysis — Analysis of 2017 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 5, 2018.

(3)

Reflects the in-the-money value of unvested stock options (subject to Anadarko’s Board of Directors approval), the estimated current value of unvested performance units (based on performance to date) and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2017. In the event of an involuntary termination, unvested performance units would be paid after the end of the applicable performance period, based on actual performance. However, the performance unit awards and the restricted stock unit awards granted on November 14, 2017, are not included in the table above as accelerated vesting upon an involuntary not for cause termination only applies to such awards if they have been held for at least 180 days after the grant date, which would not be the case in the event of such a termination that occurred on December 31, 2017. The values for Messrs. Collins and Peacock include the 10,406 allocated special restricted stock units granted on November 14, 2017, and their respective dividend equivalent units, since these grants are not subject to the 180-day hold requirement. Further, while the terms of the outstanding stock options do not require Anadarko to accelerate the vesting of the stock options upon an involuntary termination not for cause, Anadarko’s Board of Directors has a historic practice of doing so and, as such, the value of acceleration of the outstanding stock option awards is included above. The equity awards granted on and after November 10, 2016 contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31, 2017.

(4)

Reflects the lump-sum present value of additional benefits related to Anadarko’s supplemental pension benefits which are contingent upon the termination event. The value includes special pension credits, provided through an employment agreement, retention agreement, the APC Retirement Restoration Plan or the KMG Restoration Plan, as applicable. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the Partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of December 31, 2017, the expense would be as follows: Mr. Collins—$205,932.

(5)	Values represent six months of medical and dental active employee rate benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentages in effect as of December 31, 2017.

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(1)	Values assume two times the sum of base salary plus the highest bonus paid in the past three years, and reflect the allocation percentages in effect as of December 31, 2017, per the terms of the key employee change of control agreement with Anadarko. Because Mr. Casas did not work the full year in 2017, his value was calculated using an assumed at-target allocated payout in 2017.

(2)	Values assume the full-year equivalent of the applicable named executive officer’s highest annual bonus allocated to us over the past three years. The value for Mr. Casas’ highest annual bonus was based on an estimated at-target allocated payout in 2017 as he did not receive bonus payouts in the last three years.

(3)

Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2017. Upon a Change of Control, the value of unvested performance units would be calculated based on Anadarko’s total shareholder return performance and stock price at the time of the Change of Control and converted into restricted stock units of the surviving company. In the event of an involuntary not for cause termination or voluntary for good reason termination within two years following a Change of Control, the units will generally be paid on the first business day that is at least six months and one day following the separation from service. In the event of an involuntary not for cause or voluntary for good reason termination that is more than two years following a Change of Control, the units will be paid at the end of the original performance period. The equity awards granted on and after November 10, 2016, contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31, 2017.

(4)

Under the terms of the change of control agreement, our named executive officers would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming the applicable named executive officer was eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the Partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming the allocation percentages in effect as of December 31, 2017, the expense would be as follows: Mr. Fink—$110,181, Mr. Casas—$71,406, Mr. Collins—$255,189, and Mr. Peacock—$31,850.

(5)	The values reflect an additional two years of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of December 31, 2017, per the terms of their key employee change of control agreements with Anadarko.

(6)	The values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP and reflect the allocation percentages as of December 31, 2017.

(1)

Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2017. In the event of a termination as a result of disability, performance units would be paid after the end of the applicable performance period, based on actual performance. The equity awards granted on and after November 10, 2016, contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31, 2017.

(2)	Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage as of December 31, 2017.

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(1)	Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2017. All values reflect each named executive officer’s allocation percentage as of December 31, 2017.

(2)

Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage as of December 31, 2017, and exclude death benefit proceeds from programs available to all employees.

•	an annual retainer of $90,000 for each board member;

•	an annual retainer of $2,000 for each member of the Audit Committee, or $22,000 for the Committee chair;

•	an annual retainer of $2,000 for each member of the Special Committee, or $22,000 for the Committee chair;

•	a fee of $2,000 for each board meeting attended;

•	a fee of $2,000 for each committee meeting attended; and

•	annual grants of phantom units with a value of approximately $90,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko).

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•	the annual retainer was increased to $110,000 for each board member;

•	the per-meeting fee of $2,000 for each board and committee meeting attended will be paid only to the extent a board member attends in excess of 10 total board and committee meetings in one calendar year; and

•	the value of the annual grant of phantom units was increased to approximately $100,000 on the date of grant. The non-employee directors received such a grant of phantom units on May 31, 2017.

(1)

The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2017, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. As of December 31, 2017, each of the non-employee directors had 1,795 outstanding phantom units.

(1)	The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in 2017 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.

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•	each member of the Board of Directors;

•	each named executive officer of our general partner;

•	all directors and officers of our general partner as a group; and

•	Anadarko and its affiliates.

*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

(2)	WGP held 50,132,046 common units and other subsidiaries of Anadarko, AMM and AMH, collectively held 2,011,380 common units. Anadarko is the ultimate parent company of WGRI, AMM, AMH and WGP GP and may, therefore, be deemed to beneficially own the units held by such parties. Anadarko, through AMH, also held 13,243,883 Class C units of the Partnership.

(3)

Does not include 1,795 unvested phantom units that were granted to each of Messrs. Arnold, Carroll, Crane, and Tudor under the WES LTIP. Phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our Board of Directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.

(4)	Includes 2,000 units of the Partnership held in a margin account by Mr. Carroll.

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*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

(2)	As of December 31, 2017, there were 541.1 million shares of Anadarko common stock outstanding.

(3)

Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—40,516; Benjamin M. Fink—37,980; Jaime R. Casas—17,074; Craig W. Collins—27,603; Philip H. Peacock—26,697; Daniel E. Brown—47,565; and Robert K. Reeves—33,050; for a total of 230,485 unvested restricted stock units held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.

(4)

Includes 3,820 and 3,363 unvested shares of restricted common stock of Anadarko held by Craig W. Collins and Philip H. Peacock, respectively. Restricted stock awards typically vest equally over three years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.

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(1)	Based upon its Schedule 13G filed February 6, 2018, with the SEC with respect to Partnership securities held as of December 31, 2017, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 8,329,599 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 8,301,343 of the common units held by ALPS.

(2)	Based upon its Schedule 13G/A filed February 13, 2018, with the SEC with respect to WES securities held as of December 31, 2017, Tortoise Capital Advisors, L.L.C has shared voting power as to 11,857,986 common units and shared dispositive power as to 13,511,242 common units

(3)	Based upon its Schedule 13G/A filed February 6, 2018, with the SEC with respect to Partnership securities held as of December 31, 2017, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 8,974,770 common units.

(1)	Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.

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•	Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;

•

our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko (see Administrative services and reimbursement below for details regarding certain agreements for amounts reimbursed in 2017); and

•	our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets.

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•	Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;

•	Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and

•	Chipeta’s membership interests are subject to significant restrictions on transfer.

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(1)	Represents amounts earned or incurred on and subsequent to the date of acquisition of our assets, as well as amounts earned or incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)	Represents expenses incurred on and subsequent to the date of the acquisition of our assets, as well as expenses incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets.

(3)

Represents general and administrative expense incurred on and subsequent to the date of acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko and amounts charged by Anadarko under the omnibus agreement. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)	Represents interest income recognized on the note receivable from Anadarko.

(5)	Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures and Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(6)	Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(7)	Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(8)	Represents distributions paid under the partnership agreement. See Note 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(9)	See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information.

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•	approved by the Special Committee of our general partner, although our general partner is not obligated to seek such approval;

•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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