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. Includes bypass capacity at the DJ Basin and West Texas complexes.

(2)	Excludes compression horsepower for transportation.

(3)	Includes 100% of Chipeta throughput, a 50.1% share of Springfield gas gathering throughput, a 22% share of Rendezvous throughput and a 14.81% share of Fort Union throughput.

(4)

Consists of throughput on the Chipeta NGL pipeline, an NGLs line at the Brasada complex and at the DBM water systems, a 50.1% share of Springfield oil gathering throughput, a 10% share of White Cliffs throughput, a 25% share of Mont Belvieu JV throughput, a 20% share of TEG and TEP throughput, a 33.33% share of FRP throughput and a 20% share of Whitethorn 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 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.

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•	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 substantial majority of the commodity price uncertainty through the use of fee-based contracts.

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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.

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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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Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, 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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Commodity price and volumetric risk mitigation. We believe a substantial majority of our cash flows are protected from direct fluctuations caused by commodity price volatility, as 89% of our wellhead natural gas volumes (excluding equity investments) and 100% of our crude oil and produced water throughput (excluding equity investments) were attributable to fee-based contracts for the year ended December 31, 2018. 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, 2018, 64% of our natural gas throughput and 71% of our crude oil, NGLs and produced water throughput were supported by either minimum volume commitments with associated deficiency payments or cost of service commitments.

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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, 2018, we had $1.3 billion in available borrowing capacity under the RCF.

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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 nine third-party acquisitions, with an aggregate acquisition value of $6.5 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 gathered and 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 service provider 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, a customer provides liquids rich gas volumes to the service provider for processing. The service provider is obligated to return the equivalent gas volumes to the customer subsequent to processing. Due to the use and loss of volumes in processing, the service provider must purchase additional volumes to compensate the customer. In these arrangements, the service provider receives all or a portion of the NGLs produced in consideration for the service provided. These type of arrangements can expose the service provider to high levels of commodity price exposure associated with the volumes purchased to keep the customer whole, as well as for the consideration received.

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(1)	Includes 160 MMcf/d of bypass capacity at the DJ Basin complex.

(2)	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 and the Wattenberg gathering system.

(3)	We are the managing member of and own a 75% interest in Chipeta, which owns the Chipeta processing complex.

•	Customers. As of December 31, 2018, throughput at the DJ Basin complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, Anadarko’s production represented 65% of the DJ Basin complex throughput and the largest third-party customer provided 14% of the throughput.

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•	Supply. The DJ Basin complex is primarily supplied by the Wattenberg field. There were 2,122 active receipt points connected to the DJ Basin complex as of December 31, 2018. Anadarko holds interests in approximately 645,000 gross (460,000 net) acres within the DJ Basin and during the year ended December 31, 2018, turned 278 operated wells to sales in the DJ Basin.

•	Delivery points. As of December 31, 2018, 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, 2018, throughput at the Chipeta complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, 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 244,000 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 NGLs 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”).

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

(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.

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•	Customers. Throughput at the Bison treating facility was from two third-party customers as of December 31, 2018. The largest customer provided 75% of the throughput for the year ended December 31, 2018. 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.

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•	Customers. Moriah Powder River, LLC holds a majority of the firm capacity on the Fort Union system. To the extent capacity on the system is not used by this customer, it is available to third parties under interruptible agreements.

•	Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes from the Powder River Basin near Gillette, Wyoming that are either produced or gathered by the customer noted above and their affiliates. These volumes are gathered and treated under contracts with minimum volume commitments.

•	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.

•	Customers. As of December 31, 2018, gas gathered and processed through the Hilight system was from numerous third-party customers. The four largest producers provided 72% of the system throughput for the year ended December 31, 2018.

•	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 NGLs pipeline, resulting in all fractionated NGLs being sold locally through truck and rail loading facilities.

•	Customers. As of December 31, 2018, throughput at the Granger complex was from numerous third-party customers. The two largest third-party customers provided 78% of the Granger complex throughput for the year ended December 31, 2018.

•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 577 active receipt points as of December 31, 2018.

•	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, 2018, throughput at the Red Desert complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, 40% of the Red Desert complex throughput was from the two largest third-party customers and 2% 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, 2018, 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 70 MMcf/d of bypass capacity at the West Texas complex.

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

(3)	Includes 18 miles of transportation related to the Ramsey Residue Lines at the West Texas complex.

(4)	The West Texas complex includes the DBM complex and DBJV and Haley systems. Excludes 2,000 gpm of amine treating capacity.

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

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

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•	Customers. As of December 31, 2018, throughput at the West Texas complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, Anadarko’s production represented 30% of the West Texas complex throughput and the largest third-party customer provided 11% of the throughput.

•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring, Wolfcamp and Penn 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.

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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 within the West Texas complex for processing, while lean gas is delivered into Enterprise GC, L.P.’s pipeline for ultimate delivery into Energy Transfer LP’s (“ET”) Oasis pipeline (the “Oasis pipeline”). Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline. Residue gas produced at the West Texas complex is delivered to ET’s Red Bluff Express pipeline and the Ramsey Residue Lines, which extend from the complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system. NGLs production is delivered into the Sand Hills pipeline, Lone Star NGL LLC’s pipeline and EPIC Y-Grade Pipeline, LP’s NGL pipeline. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

•	Customers. As of December 31, 2018, throughput at the DBM water systems was from Anadarko and four third-party producers. Anadarko’s production represented 98% of the throughput for the year ended December 31, 2018.

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

•	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 NGLs 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.

•	Customers. Throughput at the Brasada complex was from one third-party customer as of December 31, 2018.

•	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, 2018.

•	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, ET 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.

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

•	Customers. As of December 31, 2018, the Marcellus Interest gathering systems had multiple priority shippers. The largest producer provided 86% of the throughput for the year ended December 31, 2018. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC.

•	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 and TEP 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.

(4)	We own a 20% interest in Whitethorn, which is operated by a third party.

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Customers. The White Cliffs pipeline had multiple committed shippers, including Anadarko, as of December 31, 2018. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides crude oil takeaway capacity of approximately 190 MBbls/d from Platteville, Colorado to Cushing, Oklahoma. During 2019, one of the pipelines will be converted from crude service to NGL Y-grade service with an initial capacity of 90 MBbls/d. To achieve this, the pipeline will be taken out of service in early 2019 and is expected to come back online during the fourth quarter of 2019.

•	Supply. The White Cliffs pipeline is supplied by production from the DJ Basin. At the point of origin, there is a storage facility adjacent to a truck-unloading facility.

•	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.

•	Customers. Anadarko was the only shipper on the GNB NGL pipeline as of December 31, 2018.

•	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 NGLs fractionation and storage facilities in Mont Belvieu, Texas.

•	Customers. Anadarko was the largest firm shipper on the MIGC system, with 85% of the throughput for the year ended December 31, 2018. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.

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•	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.

•	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, 2018, 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 30 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 and Adams Counties, Colorado (including the Lancaster plant, which is within the DJ Basin complex and Anadarko’s Wattenberg plant) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2018, FRP had multiple committed shippers, including Anadarko. FRP provides capacity to other shippers at the posted FERC tariff rate. In 2018, we elected to participate in the expansion of FRP, which will increase capacity by 100 MBbls/d, to a targeted total capacity of 258 MBbls/d, with the expansion expected to be completed in 2019.

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Texas Express Gathering. TEG consists of two NGLs gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGLs takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2018. In 2018, we participated in the expansion of the Texas/Oklahoma system of TEG, which has a total capacity of 100 MBbls/d and was completed in the second quarter of 2018.

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Texas Express Pipeline. TEP delivers to NGLs fractionation and storage facilities in Mont Belvieu, Texas. TEP is supplied with NGLs from other pipelines including FRP, the MAPL pipeline and TEG. As of December 31, 2018, TEP had multiple committed shippers, including Anadarko. TEP provides capacity to other shippers at the posted FERC tariff rates. In 2018, we elected to participate in the expansion of TEP, which will increase capacity by 90 MBbls/d, to a targeted total capacity of 348 MBbls/d, with the expansion expected to be completed in 2019.

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•	Mentone Train II. We are currently constructing a second cryogenic processing train at the Mentone processing plant at the West Texas complex. Mentone Train II will have a capacity of 200 MMcf/d, and we expect this train to be completed in the first quarter of 2019. Upon completion of Mentone Train II, the West Texas complex will have a total processing capacity of 1,370 MMcf/d.

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Latham processing plant. We are currently constructing two cryogenic processing trains at a new processing plant located in Weld County, Colorado. Latham Trains I and II will each have a capacity of 200 MMcf/d. Latham Train I is expected to be completed in mid-2019 and Latham Train II is expected to be completed around year-end 2019. 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 1,410 MMcf/d.

•	Equity investments. We are currently contributing to the construction of the Cactus II pipeline, a crude oil pipeline connecting West Texas to the Corpus Christi area. The Cactus II pipeline will have a total capacity of 670 MBbls/d upon completion and is expected to become operational in late 2019.

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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, operational, monitoring, and reporting requirements, and that 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 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 rulemaking as protected waters of the United States;

•	the Oil Pollution Act of 1990, which subjects, among others, 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;

•	regulations imposed by the Bureau of Land Management (the “BLM”) and the Bureau of Indian Affairs, agencies under the authority of the U.S. Department of the Interior, which govern and restrict aspects of oil and natural gas operations on federal and Native American lands, including the imposition of liabilities for pollution damages and pollution clean-up costs resulting from such operations;

•	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;

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•	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 non-producing geologic 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;

•	OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

•	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;

•	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 response preparedness.

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•	our ability to pay distributions to our unitholders;

•	our ability to consummate the Merger on the terms currently contemplated or at all;

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

•	future throughput (including Anadarko production) that 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;

•	commodity price risks inherent in our percent-of-proceeds, percent-of-product and keep-whole contracts;

•	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, as well as state-approved voter ballot initiatives, including those laws or ballot initiatives that limit Anadarko’s and other producers’ hydraulic fracturing or other oil and natural gas development or 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;

•	the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as Anadarko and we comply with any regulatory orders or other state or local changes in laws or regulations; 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, including state-approved ballot initiatives that would change state constitutions or statutes in a manner that makes future oil and gas development in such states more difficult or expensive;

•	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;

•	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.

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•	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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•	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;

•	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.

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•	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 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 under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result 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 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 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. In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed amendments that included rescission or revision of specified rule requirements, such as fugitive emission monitoring frequency. In a separate rulemaking, the BLM published a final rule in late 2016 that requires a reduction in methane emissions by regulating venting, flaring and leaking from oil and natural gas operations on public lands; however, in September 2018, the BLM published a final rule rescinding most of the new requirements of the 2016 final rule and codifying the BLM’s prior approach to venting and flaring, which rescission has been challenged in federal court and remains pending. Notwithstanding the 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 conduct operations, 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 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. Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually-determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The implementation of substantial limitations on GHG emissions in areas where we conduct operations could result in increased compliance costs to acquire emissions allowances or comply with new regulatory or reporting requirements, which developments could adversely affect demand for oil and natural gas that our customers produce, reduce demand for our services and have a material adverse effect on our business, financial condition and results of operation.

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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, property or natural resource damages and/or curtailment or suspension of operations.

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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, including environmental 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.

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

(2)	See Property exchange below.

(3)	See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.

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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.

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In August 2018, we completed an offering of $400.0 million aggregate principal amount of 4.750% Senior Notes due 2028 and $350.0 million aggregate principal amount of 5.500% Senior Notes due 2048. The net proceeds were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 7 for additional information.

•	In June 2018, we acquired a 20% interest in Whitethorn and a 15% interest in Cactus II, both from third parties. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

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In March 2018, we completed an offering of $400.0 million aggregate principal amount of 4.500% Senior Notes due 2028 and $700.0 million aggregate principal amount of 5.300% Senior Notes due 2048. The net proceeds were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 7 for additional information.

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In February 2018, we entered into the five-year $1.5 billion (expandable to $2.0 billion) RCF by amending and restating the $1.2 billion credit facility originally entered into in February 2014. In December 2018, we amended the RCF to (i) subject to consummation of the Merger (see Merger transactions below), increase the size of the RCF to $2.0 billion, and (ii) extend the maturity date of the RCF to February 2024. See Liquidity and Capital Resources within this Item 7 for additional information.

•	We commenced operation of Mentone Train I at the West Texas complex (with capacity of 200 MMcf/d) in the fourth quarter of 2018.

•	We raised our distribution to $0.980 per unit for the fourth quarter of 2018, representing a 2% increase over the distribution for the third quarter of 2018 and a 7% increase over the distribution for the fourth quarter of 2017, and resulting in a full-year 2018 distribution increase of 7% over full-year 2017.

•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,802 MMcf/d for the year ended December 31, 2018, representing a 6% increase compared to the year ended December 31, 2017.

•	Throughput for crude oil, NGLs and produced water assets totaled 365 MBbls/d for the year ended December 31, 2018, representing an 82% increase compared to the year ended December 31, 2017.

•	Operating income (loss) was $629.4 million for the year ended December 31, 2018, representing an 11% decrease compared to the year ended December 31, 2017.

•	Adjusted gross margin for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.01 per Mcf for the year ended December 31, 2018, representing a 7% increase compared to the year ended December 31, 2017.

•	Adjusted gross margin for crude oil, NGLs and produced water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.85 per Bbl for the year ended December 31, 2018, representing a 12% decrease compared to the year ended December 31, 2017.

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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; impairments; other expense; and other income attributable to the Chipeta complex.

(2)	Excludes the non-cash loss on interest-rate swaps of $8.0 million for the year ended December 31, 2018. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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(1)	Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 3—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; impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex.

(3)	See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)	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.

(5)	Reflects cash distributions of $3.830 per unit declared for the year ended December 31, 2018, including the cash distribution of $0.980 per unit paid on February 13, 2019, for the fourth-quarter 2018 distribution.

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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 Items Affecting the Comparability of Our Financial Results within this Item 7 and Note 6—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 How We Evaluate Our Operations 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)	The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now referred to as the “West Texas complex” resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating and transportation” now being reported as “Processing.”

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

(3)	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, 33.33% share of average FRP throughput and 20% share of average Whitethorn throughput.

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(1)

Includes the effects of commodity price swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016), excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—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)

For the years ended December 31, 2017 and 2016, includes the effects of commodity price swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016), excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—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 3—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), less 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, NGLs and produced water assets is calculated as total revenues and other for crude oil, NGLs and produced water assets (less reimbursements for electricity-related expenses recorded as revenue), less cost of product for crude oil, NGLs and produced water assets, and plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, the TEFR Interests and Whitethorn. See the reconciliation of Adjusted gross margin for crude oil, NGLs 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, NGLs and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGLs 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 and 2016, are presented net of $1.4 million and $6.1 million, respectively, of contributions in aid of construction costs from affiliates.

(2)	For the years ended December 31, 2018, 2017 and 2016, included $22.1 million, $6.8 million and $5.6 million, respectively, of capitalized interest.

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•	$1.2 billion of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes;

•	$161.9 million of cash paid for the acquisitions of the interests in Whitethorn and Cactus II;

•	$133.3 million of capital contributions paid to Cactus II, the TEFR Interests, Whitethorn and White Cliffs for construction activities; and

•	$25.6 million of distributions received from equity investments in excess of cumulative earnings.

•	$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 received from equity investments in excess of cumulative earnings;

•	$23.0 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015; 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;

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

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

•	$17.5 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015; and

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

•	$1.08 billion of net proceeds from the offering of the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 in March 2018, after underwriting and original issue discounts and offering costs, which were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;

•	$893.6 million of distributions paid to our unitholders;

•	$738.1 million of net proceeds from the offering of the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 in August 2018, after underwriting and original issue discounts and offering costs, which were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;

•	$690.0 million of repayments of outstanding borrowings under the RCF;

•	$534.2 million of borrowings under the RCF, net of extension and amendment costs, which were used for general partnership purposes, including to fund capital expenditures;

•	$350.0 million of principal repayment on the maturing 2.600% Senior Notes due August 2018;

•	$51.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;

•	$13.5 million of distributions paid to the noncontrolling interest owner of Chipeta; and

•	$3.4 million of issuance costs incurred in connection with the 364-day Facility.

•	$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.

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•	$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 offering of the 4.650% Senior Notes due 2026 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 5.450% Senior Notes due 2044 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;

•	$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.

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(1)

Cost of product includes product purchases from affiliates (as defined in Note 1) of $193.7 million, $86.0 million and $80.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. Operation and maintenance includes charges from affiliates of $98.8 million, $72.5 million and $72.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. General and administrative includes charges from affiliates of $45.4 million, $39.1 million and $38.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 6.

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

(3)	Includes affiliate (as defined in Note 1) amounts of zero, $(0.1) million and $7.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 3 and Note 13.

(4)	See Note 5 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 $72.8 million and $36.3 million as of December 31, 2018 and 2017, respectively.

(2)	Other current assets includes affiliate amounts of $3.7 million and zero as of December 31, 2018 and 2017, respectively.

(3)	Accrued liabilities includes affiliate amounts of $2.4 million and $0.2 million as of December 31, 2018 and 2017, respectively.

(4)	Other liabilities includes affiliate amounts of $55.7 million and $0.7 million as of December 31, 2018 and 2017, respectively.

(5)	All outstanding Class C units will convert into the Partnership’s common units on a one-for-one basis immediately prior to the closing of the Merger (as defined in Note 1), if consummated. If the Merger is not consummated, the conversion will occur on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 1 and Note 5.

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(1)	See Note 6.

(2)	See Note 3.

(3)	See Note 5.

(4)	See Note 1.

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

(2)	See Note 3.

(3)	See Note 6.

(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 6.

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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.

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•

Fee-based gathering / processing. Under Topic 605, fee revenues were 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, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, (i) revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation, (ii) deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes, and (iii) timing differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate, which results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions. In addition, under Topic 606, revenue associated with upfront or limited-term fees is recognized over the expected period of customer benefit, which is generally the life of the related properties. These revenues also include revenues earned for marketing services performed on behalf of the Partnership’s customers, and the expense associated with these marketing activities is recognized in cost of product expense, resulting in no impact to Operating income (loss).

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Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period as Service revenues – fee based. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

•

Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

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Percent-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 provides services, and the Partnership recognized revenue when the product was sold to Anadarko or 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 is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.

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Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, (i) Service revenues – product based is recognized for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost, and (ii) product sales revenue is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party. When the product is sold to Anadarko, Anadarko is acting as the Partnership’s agent in the product sale and the Partnership recognizes revenue, along with cost of product expense related to the sale, based on the Anadarko sales price to the third party, resulting in no impact to Operating income (loss).

•

Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

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(1)	Includes $(7.5) million from a performance obligation satisfied in a previous period related to the arbitration against SWEPI LP (see Note 14).

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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 2018 of $0.980 per unit, or $234.8 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, 2019, to unitholders of record at the close of business on February 1, 2019.

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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 would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the years ended December 31, 2017 and 2016. 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)	Represents the New York Mercantile Exchange forward strip price as of December 8, 2015, December 1, 2016, and December 20, 2017, for the 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 3.

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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.

(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 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 Plan within this Note 6) and amounts charged by Anadarko under the omnibus agreement.

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

(5)	Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 13).

(6)	Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

(7)	Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 3).

(8)	Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

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

(2)	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.

(3)	Includes capitalized interest of $1.4 million related to the construction of the Cactus II pipeline.

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

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(1)	See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

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(1)	See Adjustments to previously issued financial statements in Note 1—Summary of Significant Accounting Policies.

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

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(1)	The percentages presented for Ms. Fielder and Ms. Kelly represent the time allocated since their appointments as officers of our general partner.

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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, as amended and restated (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 and change of control benefits, and 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 Anadarko’s 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, 2018, 2017 and 2016. Ms. Fielder’s amount reflects base salary compensation earned and allocated since her appointment as President on November 15, 2018. Ms. Kelly’s amount reflects base salary compensation earned and allocated since her appointment as the principal operating officer on May 13, 2018.

(2)

The amounts in this column reflect the expected allocation to us of the aggregate grant date fair value of the awards, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the Omnibus Plan. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 23—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, 2018 (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 2018, 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 Omnibus Plan. See note (2) above for valuation assumptions. The value ultimately realized upon the exercise of the stock option(s) may or may not be equal to this determined value. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 23—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, 2018 (which is not, and shall not be deemed to be, incorporated by reference herein). For information regarding the option awards granted to the named executives in 2018, see the Grants of Plan-Based Awards table.

(4)

The amounts in this column reflect the compensation under Anadarko’s AIP expected to be allocated to us for the year ended December 31, 2018, and allocated to us for the years ended December 31, 2017 and 2016. Given the timing of when payments are to be made in 2019, the 2018 amounts represent estimates of the payments which were earned in 2018 and are expected to be paid in early 2019, which may not be indicative of the payout our named executive officers will actually receive. The 2017 amounts represent payments which were earned in 2017 and paid in early 2018 and the 2016 amounts represent the payments which were earned in 2016 and paid in early 2017. For an explanation of the 2018 annual incentive plan awards, read Compensation Discussion and Analysis – 2018 Compensation Structure and Decisions Link Direct Compensation Elements to Strategy and Outcomes – Performance-Based Annual Incentive Program (AIP), contained within Anadarko’s proxy statement for its 2019 annual meeting of stockholders, which is expected to be filed no later than April 4, 2019.

(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, 2018, 2017 and 2016. Ms. Fielder’s amount reflects allocated expenses beginning November 15, 2018, the date of her appointment as President. Ms. Kelly’s amount reflects allocated expenses beginning May 13, 2018, the date of her appointment as the principal operating officer. The 2018 allocated expenses are detailed in the table below:

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(1)

Reflects the estimated 2018 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 2018 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 – 2018 Compensation Structure and Decisions Link Direct Compensation Elements to Strategy and Outcomes – Performance-Based Annual Incentive Program (AIP) contained within Anadarko’s proxy statement for its 2019 annual meeting of stockholders, which is expected to be filed no later than April 4, 2019.

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(2)

Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in 2018. 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. For additional discussion of Anadarko’s performance unit awards, read Compensation Discussion and Analysis – 2018 Compensation Structure and Decisions Link Direct Compensation Elements to Strategy and Outcomes – Equity Compensation contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 4, 2019.

(3)

Reflects the allocable number of shares of restricted stock and restricted stock units awarded in 2018 under the Omnibus Plan. Generally speaking, these awards vest ratably on each of the first three anniversaries of the grant date. For shares of restricted stock, 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 2018, Ms. Kelly received shares of restricted stock on March 13, 2018, prior to her appointment as an officer, and restricted stock units on May 7, 2018, in connection with her promotion and appointment as the principal operating officer; both grants vest ratably on each of the first three anniversaries of the grant date. Also included are the allocated 16,214 special restricted stock units awarded under the Omnibus Plan to Mr. Casas in 2018, which will fully vest four years from the grant date, provided Mr. Casas remains employed by Anadarko until such date.

(4)	Reflects the allocable number of Anadarko stock options each named executive officer was awarded in 2018. Generally, these awards vest ratably on each of the first three anniversaries of the grant date and have a term of seven years.

(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 2018 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 23—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, 2018 (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, the restricted stock units and shares of restricted stock will vest ratably over three years in equal installments on the first, second, and third anniversaries 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 Anadarko common stock, less applicable withholding taxes. For shares of restricted stock, 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 following outstanding allocated special restricted stock units, including their corresponding dividend equivalent units, will fully vest four years from their respective grant dates, provided Messrs. Fink, Casas and Peacock and Ms. Fielder remain employed by Anadarko until such dates: 13,293 for Mr. Fink, 16,325 for Mr. Casas, 5,745 for Ms. Fielder and 10,606 for Mr. Peacock; these numbers include their corresponding dividend equivalent units as of December 31, 2018 and the actual number of shares that vest may differ from these values.

(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, 2018, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. The three-year performance period generally starts in January following the year of grant, however the February 2017 grant to Mr. Fink and the March 2017 grant to Mr. Peacock uses the performance period of the November 2016 grant which is January 1, 2017 to December 31, 2019. Anadarko’s relative performance rankings as of December 31, 2018 were: 60% for the October 2015 grant, 60% for the November 2016 and February and March 2017 grants, and 164% for the November 2017 grant. For awards granted in November 2018 with a performance period beginning in 2019, target payout has been assumed.

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(1)

Shares acquired and values realized on exercise include options exercised in 2018. The amounts shown in the “Value Realized on Exercise” column represent the difference between the market price of Anadarko common stock at exercise and the applicable exercise price of such option(s). 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 2018 of shares of restricted stock or restricted stock units, performance units, or phantom units. For each named executive officer, the amount shown in the “Value Realized on Vesting” column represents the aggregate number of restricted stock units or shares of restricted stock held by such named executive officer that vested during 2018 multiplied by the market price of Anadarko common stock on the applicable vesting date(s). For shares of restricted stock or restricted stock 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)

Reflects the value (determined as the excess, if any, of the fair market value of a share as of December 31, 2018, over the exercise price of such share (the “in-the-money value”)) of allocated unvested stock options. The nonqualified stock option agreements provide for continued vesting according to the time-based vesting schedule in cases of qualified retirement (which means retirement at or after age 60 with minimum 10 years of service). As of December 31, 2018, none of our named executive officers were eligible for qualified retirement.

(2)

Under the terms of the performance unit agreements, 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 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, 2018, none of our named executive officers were eligible for retirement nor qualified retirement.

(3)	Under the terms of the restricted stock unit agreements, in the event of a qualified retirement, restricted stock units will be settled according to the vesting schedule. As of December 31, 2018, none of our named executive officers were eligible for qualified retirement.

(1)	The values assume two times base salary plus one times target AIP bonus. All values reflect each named executive officer’s estimated allocation percentage during the fiscal year ended December 31, 2018.

(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 officers’ bonus awarded under the annual incentive plan. For additional discussion of this program, read Compensation Discussion and Analysis – 2018 Compensation Structure and Decisions Link Direct Compensation Elements to Strategy and Outcomes – Performance-Based Annual Incentive Program (AIP) of Anadarko’s proxy statement for its 2019 annual meeting of stockholders, which is expected to be filed no later than April 4, 2019.

(3)

Reflects the in-the-money value of unvested stock options (subject to Anadarko’s Board of Directors approval of the acceleration of such stock options, as discussed below), the estimated current value of unvested performance units (based on performance to date) and the value of unvested shares of restricted stock and restricted stock units granted under the Omnibus Plan, all as of December 31, 2018. 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. 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 estimated allocation percentage during the fiscal year ended December 31, 2018.

(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, 2018, the expense would be as follows: Ms. Fielder—$111,430 and Ms. Kelly—$162,249.

(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 the applicable and estimated allocation percentages for each named executive officer during the fiscal year ended December 31, 2018.

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(1)

For Mr. Fink, the value assumes two and a half times the sum of base salary in effect at the end of 2018 and his target annual bonus for the year in which the date of termination occurs. For all other named executive officers, values assume two times the sum of base salary plus the highest bonus paid in the past three years, per the terms of the key employee change of control agreement with Anadarko. Mr. Casas’ value was calculated using his bonus payout in 2018 since he did not receive bonus payouts in the prior two years. All values reflect the estimated allocation percentages during the fiscal year ended December 31, 2018.

(2)

For Mr. Fink, the value assumes pro-rata bonus based on the target AIP bonus percentage in effect for the year of termination, base salary in effect at the beginning of the year and Anadarko’s actual performance, as may be allocated under the Omnibus Agreement. For all other named executive officers, 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 the payout in 2018 as he did not receive bonus payouts in the prior two years. All values reflect the estimated allocation percentages during the fiscal year ended December 31, 2018.

(3)

Reflects the in-the-money value of unvested stock options, the value of unvested shares of restricted stock and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under the Omnibus Plan, all as of December 31, 2018. 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 estimated allocation percentage during the fiscal year ended December 31, 2018.

(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, 2018, the expense would be as follows: Mr. Fink—$304,226, Mr. Casas—$99,812, Ms. Fielder—$402,040, Ms. Kelly—$315,397, and Mr. Peacock—$50,809.

(5)

For Mr. Fink, the values reflect an additional three years of employer contributions into the savings restoration plan at his current contribution rate to the plan and is based on his estimated allocation percentage during the fiscal year ended December 31, 2018. For all other named executive officers, 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 estimated allocation percentages during the fiscal year ended December 31, 2018, per the terms of their key employee change of control agreements with Anadarko.

(6)	The values represent 36 months and 24 months of health and welfare benefit coverage for Mr. Fink and all other named executive officers, respectively. These amounts are present values determined in accordance with GAAP and reflect the estimated allocation percentages during the fiscal year ended December 31, 2018.

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(1)

Reflects the in-the-money value of unvested stock options, the value of unvested shares of restricted stock and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under the Omnibus Plan, all as of December 31, 2018. 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 estimated allocation percentage during the fiscal year ended December 31, 2018.

(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 estimated allocation percentage during the fiscal year ended December 31, 2018.

(1)	Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested shares of restricted stock and restricted stock units granted under the Omnibus Plan, all as of December 31, 2018. All values reflect each named executive officer’s estimated allocation percentage during the fiscal year ended December 31, 2018.

(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 estimated allocation percentage during the fiscal year ended December 31, 2018, and exclude death benefit proceeds from programs available to all employees.

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•	an annual retainer of $110,000 for each non-employee Board member;

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

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

•	a fee of $2,000 for each Board and committee meeting attended to the extent a non-employee Board member attends in excess of 10 total Board and committee meetings in one calendar year; and

•	annual grants of phantom units with a value of approximately $100,000 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).

(1)

The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2018, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. As of December 31, 2018, each of the non-employee directors held 2,005 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 2018 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 value included above.

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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 14,681,388 Class C units of the Partnership.

(3)

Does not include 2,005 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.

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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, 2018, there were 499.6 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—45,166; Benjamin M. Fink—41,815; Jaime R. Casas—38,689; Robin H. Fielder—31,163; Gennifer F. Kelly—10,279; Philip H. Peacock—27,887; Daniel E. Brown—57,215; and Mitchell W. Ingram—43,948; for a total of 296,162 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)	In 2017, Mr. Gwin transferred the economic interest in certain stock options and restricted stock units of Anadarko common stock pursuant to a domestic relations order. The shares reported do not reflect the stock options or restricted stock units in which he has no economic or beneficial interest.

(5)

Includes 872, 5,670 and 1,331 unvested shares of restricted common stock of Anadarko held by Robin H. Fielder, Gennifer F. Kelly 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 12, 2019, with the SEC with respect to Partnership securities held as of December 31, 2018, Tortoise Capital Advisors, L.L.C. has shared voting power as to 14,143,949 common units and shared dispositive power as to 15,658,185 common units and sole voting and dispositive power over 120,979 common units.

(2)	Based upon its Schedule 13G filed February 4, 2019, with the SEC with respect to Partnership securities held as of December 31, 2018, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 9,954,452 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 9,954,452 of the common units held by ALPS.

(3)	Based upon its Schedule 13G/A filed February 1, 2019, with the SEC with respect to Partnership securities held as of December 31, 2018, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 8,629,682 common units and Richard A. Kayne has sole voting and dispositive power over 95,356 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 2018); 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 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.

(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 acquisition of Partnership assets, as well as a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of Partnership 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 6—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 3—Acquisitions and Divestitures and Note 13—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 3—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 3—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 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(9)	See Note 6—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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