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

(2)

Includes 100% of Chipeta throughput, 50% of Newcastle and DBJV system throughput, 50.1% of Springfield gas gathering throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput, but excludes throughput related to the Hugoton system (44 MMcf/d for the ten months ended October 31, 2016) prior to its divestiture in October 2016 (see Acquisitions and Divestitures within these Items 1 and 2).

(3)

Represents total throughput measured in barrels, consisting of throughput on our Chipeta NGL pipeline and an NGL line at our Brasada complex, our 50.1% share of average Springfield oil gathering system throughput, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput. See Properties below for further descriptions of these systems.

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

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

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

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

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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.

•	Affiliation with Anadarko. We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its relationships throughout the energy industry, including those with producers and customers in the United States, to pursue projects that help to enhance the value of our business. See Our Relationship with Anadarko Petroleum Corporation below.

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Commodity price and volumetric risk mitigation. Our cash flows are relatively protected from fluctuations caused by commodity price volatility due to (i) the approximately 94% of our Adjusted gross margin attributable to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to a majority of our percent-of-proceeds and keep-whole contracts. For the year ended December 31, 2016, 99% of our Adjusted gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. See How We Evaluate Our Operations under Part II, Item 7 of this Form 10-K. On December 1, 2016, we renewed our commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets through December 31, 2017. See Risk Factors under Part I, Item 1A and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. In addition, we mitigate volumetric risk by entering into contracts with cost of service or demand charge structures. For the year ended December 31, 2016, and excluding throughput measured in barrels, 54% of our throughput was subject to demand charges and 27% of our throughput was contracted under a cost of service model.

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Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-term relationships and reasonable access to debt and equity capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of December 31, 2016, we had no outstanding borrowings under our RCF and $4.9 million in outstanding letters of credit issued under our $1.2 billion RCF.

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Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, and the Eagleford shale, which have historically seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas serve production where the hydrocarbons contain not only natural gas, but also oil, condensate and NGLs. In addition, our interest in the Anadarko-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which is considered to have some of the most abundant low-cost, dry gas reserves due to the overall scale and quality of the underlying resource. See Properties below for further asset descriptions and Note 14—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

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Consistent track record of accretive acquisitions. Since our IPO in 2008, our management team has successfully executed eleven related-party acquisitions and six third-party acquisitions, with an aggregate value of $5.6 billion (inclusive of the forecasted cash payment of $56.5 million for the acquisition of DBJV in March 2020, see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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 in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. 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 also serve as 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.

•	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 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 both throughout the pipeline network and 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 byproduct of crude oil and natural gas production, produced water must be recycled or disposed of in order to maintain production. Produced water disposal wells and related facilities remove hydrocarbon products and other sediments from the produced water in compliance with applicable regulations and re-inject it into an underground formation.

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

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

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

•	Firm. Firm service requires the reservation of capacity by a customer between certain receipt and delivery points or within a processing facility. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus, in specific cases, a usage fee based on the volumes gathered, processed or transported.

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Interruptible. Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume actually gathered, processed or transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and, as such, customers receiving services under interruptible contracts are not assured capacity.

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

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

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

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

•	Customers. Throughput at the Bison treating facility was from two third party customers for the year ended December 31, 2016. The largest customer provided 78% of the throughput during the year ended December 31, 2016.

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

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

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

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

◦	Colorado Interstate Gas Company LLC’s pipeline (“CIG”);

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

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

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•	Customers. Gas gathered and processed through the Hilight system is from numerous third-party customers, with the six largest producers providing 79% of the system throughput during the year ended December 31, 2016.

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

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

•	Customers. Gas gathered and processed through the Newcastle system is from 11 third-party customers, with the largest three producers providing 79% of the system throughput during the year ended December 31, 2016. The largest producer provided 48% of the throughput during the year ended December 31, 2016.

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

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

•	Customers. For the year ended December 31, 2016, 89% of the Granger complex throughput was from five third-party customers and 2% was from Anadarko.

•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 593 active receipt points as of December 31, 2016.

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

◦	CIG;

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

◦	Questar Pipeline Company’s pipeline (“Questar pipeline”);

◦	Questar 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. For the year ended December 31, 2016, 61% of the Red Desert complex throughput was from six third-party customers and 7% 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 CIG and WIC, while NGLs are delivered to MAPL, as well as to truck and rail loading facilities.

•	Customers. Tesoro and Anadarko are the only firm customers on the Rendezvous gathering system. To the extent capacity on the system is not used by those customers, it is available to third parties under interruptible agreements.

•	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 Tesoro’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.

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

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

(3)	At current carbon dioxide levels and operating conditions.

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•	Customers. Anadarko is the largest customer with 70% of the DJ Basin complex throughput for the year ended December 31, 2016. The balance of the throughput was from various third-party customers, with the largest providing 15% of the throughput.

•	Supply. There were 2,598 active receipt points connected to the DJ Basin complex as of December 31, 2016. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko controls 749,000 gross acres. Anadarko drilled 97 wells and completed 204 wells during the year ended December 31, 2016.

•	Delivery points. As of December 31, 2016, 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.

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•	Customers. Anadarko is the largest customer at Chipeta with 77% of the system throughput for the year ended December 31, 2016. The balance of throughput during the year ended December 31, 2016 was from 9 third-party customers.

•	Supply. The Chipeta complex is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko controls 255,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Questar pipeline and Three Rivers Gathering, LLC’s system, which is owned by Ute Energy and another third party.

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

◦	CIG;

◦	Questar pipeline; and

◦	WIC.

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•	Customers. Anadarko is the only shipper on the Clawson gathering system.

•	Supply. The Clawson Springs field covers 7,600 gross acres and produces primarily from the Ferron Coal play.

•	Delivery points. The Clawson gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.

•	Customers. Anadarko is the only shipper on the Helper gathering system.

•	Supply. The Helper and the Cardinal Draw fields are Anadarko-operated coal-bed methane developments on the southwestern edge of the Uinta Basin that produce from the Ferron Coal play. Anadarko owns 19,000 gross acres in the Helper field and 16,000 gross acres in the Cardinal Draw field.

•	Delivery points. The Helper gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.

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(1)	WES owns a 33.75% interest in the Non-Operated Marcellus Interest gathering systems, with a third party serving as the operator.

(2)	WES owns a 33.75% interest in the Anadarko-Operated Marcellus Interest gathering systems, with Anadarko serving as the operator.

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Customers. As of December 31, 2016, in addition to Anadarko, the Non-Operated Marcellus Interest gathering systems had seven priority shippers on its Rome gathering system and eight priority shippers on its Liberty gathering system. Also as of December 31, 2016, in addition to Anadarko, the Anadarko-Operated Marcellus Interest gathering systems had six priority shippers. For the year ended December 31, 2016, Anadarko represented 18% and 43% of throughput on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively. Capacity not used by priority shippers is available to third parties.

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Supply and delivery points. As of December 31, 2016, Anadarko had a working interest in over 533,000 gross acres within the Marcellus shale. On December 21, 2016, Anadarko announced it had agreed to sell its operated and non-operated upstream assets and operated midstream assets (excluding the Partnership’s interests) in the Marcellus shale to a third party, including approximately 195,000 net acres. The transaction is expected to close in the first quarter of 2017, subject to standard closing conditions and adjustments. The Non-Operated Marcellus Interest gathering systems have access to Transcontinental Gas Pipeline Company, LLC’s pipeline (“TRANSCO”), Tennessee Gas Pipeline Company, LLC’s pipeline and Millennium Pipeline Company, LLC’s pipeline. The Anadarko-Operated Marcellus Interest gathering systems have access to TRANSCO.

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

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

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

(4)	Excludes 1,400 gpm of amine treating capacity at the DBM complex. Train VI is currently under construction. See Assets Under Development below.

(5)	We own a 50% interest in the DBJV system and serve as the operator.

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

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

•	Customers. Anadarko provides 100% of the throughput to the Brasada complex. Anadarko delivers gas and NGLs to the plant on behalf of itself and its upstream joint interest owners.

•	Supply. Brasada is supplied from Anadarko’s production in the Eagleford shale, in which Anadarko controlled 345,000 gross acres. As noted above, in January 2017, Anadarko announced the sale of its Eagleford shale upstream assets to third parties.

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•	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. Anadarko’s production represented 49% of the Springfield gas gathering system’s throughput, and 47% of the Springfield oil gathering system’s throughput for the year ended December 31, 2016. The remaining throughput was attributable to three third-party producers for the gas gathering system and the oil gathering system.

•	Supply. Supply of gas and oil comes from Anadarko’s production in the Eagleford shale, in which Anadarko controlled 345,000 gross acres. As noted above, in January 2017, Anadarko announced the sale of its Eagleford shale upstream assets to third parties.

•	Delivery points. The gas gathering system delivers rich gas to our Brasada complex and to processing plants operated by Enterprise, Energy Transfer Partners, LP (“ETP”) and Kinder Morgan, Inc. The oil gathering system has delivery points to Plains All American Pipeline, Kinder Morgan, Inc.’s Double Eagle Pipeline, Hilcorp Energy Company’s Harvest Pipeline and NuStar Energy’s Pipeline.

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•	Customers. Anadarko’s production represented 83% of the Haley gathering system’s throughput for the year ended December 31, 2016. The remaining throughput was attributable to two third-party producers.

•	Supply. As of December 31, 2016, Anadarko held an interest in over 580,000 gross acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.

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Delivery points. The Haley gathering system provides both lean and rich gas gathering service. The lean service delivery point is into Enterprise GC, LLC’s pipeline for ultimate delivery into ETP’s Oasis pipeline (the “Oasis pipeline”). The rich service system delivery point is into a high pressure gathering line (the “Avalon Express pipeline”), which is part of our DBJV system. The Avalon Express pipeline can deliver gas into either the Bone Spring Gas Processing plant (the “Bone Spring plant”) or the Mi Vida Gas Processing plant (the “Mi Vida plant”), both of which are partially owned by Anadarko. Downstream pipelines at the plant tailgates include the Oasis and Transwestern pipelines at the Bone Spring plant and the Oasis pipeline at the Mi Vida plant. These downstream pipelines provide transportation to both the Waha Hub and Houston Ship Channel markets.

•	Customers. Gas gathered and processed through the DBM complex is primarily from third-party producers, with the three largest producers providing 46% of the system throughput for the year ended December 31, 2016.

•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko holds an interest in over 580,000 gross acres within the Delaware Basin.

•	Delivery points. Residue gas produced at the facility is delivered to an interconnect with the El Paso Natural Gas pipeline. NGL production is delivered into both the Sand Hills pipeline and Lone Star NGL LLC’s pipeline.

•	Customers. Anadarko’s production represented 80% of the DBJV system’s throughput for the year ended December 31, 2016. The remaining throughput was attributable to one third-party producer.

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

•	Delivery points. Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to both the Bone Spring plant and the Mi Vida plant for processing, while lean Penn gas is delivered into Enterprise GC, LP’s pipeline. Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern pipeline.

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

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

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

•	Customers. Anadarko is the largest firm shipper on the MIGC system, with 89% of the throughput for the year ended December 31, 2016. The remaining throughput on the MIGC system was from 16 third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.

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

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

◦	CIG;

◦	TIGT; and

◦	WIC.

•	Customers. For the year ended December 31, 2016, 11% 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 contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements.

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

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•	Customers. Anadarko was the only shipper on the GNB NGL pipeline for the year ended December 31, 2016.

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

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

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Customers. The White Cliffs pipeline had multiple committed shippers, including Anadarko, during the year ended December 31, 2016. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides 150 MBbls/d of crude takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. White Cliffs is currently undergoing an expansion project that will increase the pipeline’s capacity to approximately 215 MBbls/d. This expansion project is scheduled to be completed early in the second quarter of 2017.

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

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

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Front Range Pipeline. FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld County, Colorado (including our Lancaster plant, which is within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. During the year ended December 31, 2016, FRP had multiple committed shippers, including Anadarko, and provides capacity for other shippers at the posted FERC tariff rate.

•	Texas Express Gathering. TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper during the year ended December 31, 2016.

•	Texas Express Pipeline. TEP delivers to NGL fractionation and storage facilities in Mont Belvieu, Texas. At Skellytown, Texas, TEP is supplied with NGLs from other pipelines including FRP and MAPL. TEP had multiple committed shippers, including Anadarko, during the year ended December 31, 2016 and provides capacity for other shippers at the posted FERC tariff rates.

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•	DBM Train VI: The 200 MMcf/d cryogenic train is under construction and is expected to be completed during the fourth quarter of 2017. The DBM complex will have 900 MMcf/d processing capacity upon completion.

•	Mentone gas plant: We have sanctioned a new gas processing plant which will be located in Loving County, Texas. This plant will have connections to the DBJV system in West Texas. Engineering and procurement of equipment has begun and the construction of the initial cryogenic trains (Mentone Trains I and II) is expected to begin during the fourth quarter of 2017.

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Produced-water disposal systems: The River Reeves and Silvertip systems located in Reeves County and Loving County, Texas, respectively, are currently under construction with expected in-service dates during the second quarter of 2017. The River Reeves and Silvertip systems are expected to have produced-water disposal capacities of 30 MBbls/d and 60 MBbls/d, respectively. The two facilities currently have contracts in place with a subsidiary of Anadarko.

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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, imposes various pre-construction, monitoring, and reporting requirements, which the U.S. Environmental Protection Agency (the “EPA”) has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions.

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

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

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

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

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

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

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

•	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.

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•	our ability to pay distributions to our unitholders;

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

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

•	our operating results;

•	competitive conditions;

•	technology;

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

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

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

•	weather and natural disasters;

•	inflation;

•	the availability of goods and services;

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

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

•	environmental liabilities;

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

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•	changes in the financial or operational condition of Anadarko;

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

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

•	our commitments to capital projects;

•	our ability to use our 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 and transportation agreements and our $260.0 million note receivable from Anadarko;

•	the timing, amount and terms of future issuances of equity and debt securities; 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 and operating risks, including potential environmental liabilities;

•	transportation capacity constraints and interruptions;

•	adverse effects of governmental and environmental regulation;

•	shareholder activism with respect to Anadarko’s stock or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas by Anadarko in order to minimize emissions of carbon dioxide, a GHG; 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;

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•	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 energy companies;

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

•	prevailing economic conditions.

•	our level of capital expenditures;

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

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

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

•	restrictions contained in debt agreements to which we are a party or with respect to any outstanding preferred units; and

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

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

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

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

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

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

•	unforeseen difficulties operating in new geographic areas; and

•	customer or key employee losses at the acquired businesses.

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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 energy business; or

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

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

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

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

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

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Ground-Level Ozone Standards. In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017, and any designations or requirements that result in reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this rule 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 June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified, or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012, known as Subpart OOOO, by using certain equipment specific emissions control practices with respect 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. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural gas industry. The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. Compliance with this rule could, among other things, require installation of new emission controls on some of our equipment and significantly increase our capital expenditures and operating costs.

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Reduction of Greenhouse Gas Emissions. The U.S. Congress and the EPA, in addition to some state and regional efforts, 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. Furthermore, the EPA has passed a rule, known as the Clean Power Plan, to limit GHGs from power plants, but on February 9, 2016, the U.S. Supreme Court stayed this rule while it is being challenged in the federal D.C. Circuit Court of Appeals. If this rule survives legal challenge, then depending on the methods used to implement this rule, it could reduce demand for the oil and natural gas our customers produce or increase the cost of electricity for our operations. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. The adoption and implementation of any federal or state legislation or regulations that restrict emissions of GHGs or other air emissions could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.

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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 as a result of the malfunction of equipment or facilities;

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

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

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

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

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

•	The officers of our general partner will also devote significant time to the business of Anadarko and will be 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;

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•	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)	Concurrently with the closing of our IPO, Anadarko contributed the initial assets to us.

(2)	Acquired the Powder River assets, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union.

(3)	Acquired a 10% interest in White Cliffs, which consisted of a 9.6% third-party interest and a 0.4% interest from Anadarko.

(4)	Acquired Anadarko’s then-remaining 24% membership interest in Chipeta, receiving distributions related to the additional interest effective July 1, 2012.

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

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

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•	We completed the acquisition of Springfield from Anadarko for cash and common unit consideration totaling $750.0 million. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

•	We issued 21,922,831 Series A Preferred units to private investors, generating net proceeds of $686.9 million, a portion of which was used to fund the acquisition of Springfield. See Equity Offerings under Part I, Items 1 and 2 of this Form 10-K for additional information.

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We completed the offering of $500.0 million aggregate principal amount of 2026 Notes in July 2016 and an offering of an additional $200.0 million in aggregate principal amount of 2044 Notes in October 2016. Net proceeds were used to repay amounts then outstanding under our RCF and for general partnership purposes, including capital expenditures. See Liquidity and Capital Resources within this Item 7 for additional information.

•	We commenced operation of Trains IV and V at the DBM complex in May 2016 and October 2016, respectively. Both are 200 MMcf/d processing plants. Further, after sustaining damage during the December 3, 2015, incident at the DBM complex, Train II (with capacity of 100 MMcf/d) returned to service in December 2016 and Train III (with capacity of 200 MMcf/d) returned to service in May 2016.

•	We received $33.8 million in cash proceeds from insurers related to the incident at the DBM complex, including $16.3 million for business interruption insurance claims and $17.5 million for property insurance claims. See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information.

•	We raised our distribution to $0.860 per unit for the fourth quarter of 2016, representing a 2% increase over the distribution for the third quarter of 2016 and an 8% increase over the distribution for the fourth quarter of 2015.

•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,940 MMcf/d for the year ended December 31, 2016, representing a 5% decrease compared to the year ended December 31, 2015.

•	Throughput for crude/NGL assets totaled 184 MBbls/d for the year ended December 31, 2016, representing a 1% decrease compared to the year ended December 31, 2015.

•	Operating income (loss) was $708.2 million for the year ended December 31, 2016, representing a 350% increase compared to the year ended December 31, 2015.

•	Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $0.83 per Mcf for the year ended December 31, 2016, representing a 12% increase compared to the year ended December 31, 2015.

•	Adjusted gross margin for crude/NGL assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $2.11 per Bbl for the year ended December 31, 2016, representing a 9% increase compared to the year ended December 31, 2015.

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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 energy industry, without regard to financing methods, capital structure or historical cost basis;

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

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

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

(2)	Excludes income of $0.5 million for the year ended December 31, 2014, related to a component of a gas processing agreement accounted for as a capital lease.

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

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

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

(4)	Excludes income of $0.5 million for the year ended December 31, 2014, related to a component of a gas processing agreement accounted for as a capital lease.

(5)	Reflects cash distributions of $3.350 per unit declared for the year ended December 31, 2016.

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DBM acquisition. In November 2014, we acquired Nuevo from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC. We financed the acquisition with the issuance of $750.0 million of Class C units to a subsidiary of Anadarko, borrowings under our RCF and cash on hand, including the proceeds from the November 2014 equity offering. These assets have been recorded in our consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the DBM acquisition were included in our consolidated statement of operations beginning on the acquisition date in the fourth quarter of 2014.

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DBJV acquisition. In March 2015, we acquired Anadarko’s interest in DBJV. We will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. As of the acquisition date, we estimated the future payment to be $282.8 million, the net present value of which was $174.3 million. As of December 31, 2016, the net present value of this obligation was $41.4 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion revision was $7.7 million for the year ended December 31, 2016, and accretion expense was $14.4 million and zero for the years ended December 31, 2015 and 2014, respectively.

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

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

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(1)

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

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

(3)

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

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

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

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(1)	Excludes amounts considered above market, with respect to our swap extensions at the DJ Basin complex and the Hugoton system beginning July 1, 2015, that are recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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(1)	Excludes amounts considered above market, with respect to our swap extensions at the DJ Basin complex and the Hugoton system beginning July 1, 2015, that are recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

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(1)

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

(2)

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

(3)	For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP 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 to GAAP measures within this Item 7.

(4)	Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP 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/NGL assets, divided by total throughput (MBbls/d) for crude/NGL 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, 2016, 2015 and 2014, are presented net of $6.1 million, $0.5 million and $0.2 million, respectively, of contributions in aid of construction costs from affiliates.

(2)	Includes the noncontrolling interest owner’s share of Chipeta’s capital expenditures for all periods presented. For the years ended December 31, 2016, 2015 and 2014, included $5.6 million, $8.3 million and $9.8 million, respectively, of capitalized interest.

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•	$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;

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

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

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

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

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

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

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

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

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

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•	$1.5 billion of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;

•	$804.8 million of capital expenditures, net of $0.2 million of contributions in aid of construction costs from affiliates, primarily related to the construction of Lancaster Trains I and II, as well as compression expansion projects, all within the DJ Basin complex;

•	$356.3 million of cash paid for the acquisition of the TEFR Interests;

•	$42.0 million of cash paid related to the construction of the Front Range Pipeline, which was completed in March 2014;

•	$22.9 million of cash paid for equipment purchases from Anadarko;

•	$10.5 million of cash paid for White Cliffs expansion projects;

•	$6.6 million of cash paid related to the construction of the Texas Express Pipeline, which was completed in November 2013;

•	$18.1 million of distributions from equity investments in excess of cumulative earnings; and

•	$13.0 million of net proceeds, after closing adjustments, from the sale of a gathering system to a third party in September 2014.

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

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

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

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

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

•	$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;

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

•	$900.0 million of repayments of outstanding borrowing under our RCF;

•	$671.9 million of distributions paid to our unitholders;

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

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

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

•	$545.1 million of distributions paid to our unitholders;

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

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

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

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

•	$57.4 million of net proceeds from sales of common units under the $500.0 million COP (as discussed in Securities within this Item 7). Net proceeds were used for general partnership purposes, including funding capital expenditures; and

•	$18.4 million of capital contribution from Anadarko related to the above-market component of swap extensions.

•	$750.0 million of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;

•	$603.0 million of net proceeds from the November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;

•	$475.0 million of borrowings to fund a portion of the acquisition of DBM;

•	$389.5 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;

•	$350.0 million of borrowings to fund the acquisition of the TEFR Interests;

•	$335.0 million of borrowings to fund capital expenditures and general partnership purposes;

•	$100.0 million of net proceeds from the offering of additional 2018 Notes in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of the outstanding borrowings under our RCF;

•	$83.2 million of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;

•	$18.1 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering;

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•	$650.0 million of repayments of outstanding borrowings under our RCF;

•	$408.6 million of distributions paid to our unitholders;

•	$16.4 million of net distributions to Anadarko representing intercompany transactions attributable to the acquisitions of Springfield, DBJV and the TEFR Interests; and

•	$15.1 million of distributions paid to the noncontrolling interest owner of Chipeta.

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•	significant changes in our unit price;

•	significant declines in commodity prices;

•	significant increases in operating and capital costs;

•	impairments recognized;

•	acquisitions and disposals of assets;

•	changes in throughput; and

•	significant declines in trading multiples for our peers.

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(1)

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $80.5 million, $167.4 million and $127.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Operation and maintenance includes charges from Anadarko of $72.3 million, $77.1 million and $71.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. General and administrative includes charges from Anadarko of $38.1 million, $33.9 million and $31.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 5.

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

(3)	Includes affiliate (as defined in Note 1) amounts of $7.7 million, $(14.4) million and zero for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 2 and Note 12.

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

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

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(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $76.6 million and $42.7 million as of December 31, 2016 and 2015, respectively. Accounts receivable, net as of December 31, 2016 and 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.

(2)	See Note 2.

(3)	The Series A Preferred units are convertible into common units at the holder’s election on a one-for-one basis at any time after the second anniversary of the issuance date. See Note 4.

(4)	The Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 4.

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(1)	Includes deferred taxes on capitalized interest of $0.3 million associated with the acquisition of the TEFR Interests (as defined and described in Note 1).

(2)	See Note 5.

(3)	See Note 2.

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

(2)	See Note 5.

(3)	For the year ended December 31, 2014, represents transfers of $4.6 million from other long-term assets associated with the capital lease component of a processing agreement.

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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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(1)

The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million.

(2)

The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price.

(3)

The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below.

(4)

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

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

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

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

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(1)

The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2016 of $0.860 per unit, or $170.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution was paid on February 13, 2017, to unitholders of record at the close of business on February 2, 2017.

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(1)	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

(2)

Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.

(3)	Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.

(4)

Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.

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

(2)	The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015.

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

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

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

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

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

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

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

(5)	For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12).

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

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

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

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(1)

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

(2)

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

(3)

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

(4)

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

(5)

The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

(6)

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

(7)

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

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

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

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

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(1)	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies).

(2)	Includes impairments at the Red Desert complex in the first and fourth quarters of 2015 and at the Hilight system in the fourth quarter of 2015. See Note 7—Property, Plant and Equipment.

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•	base salary;

•	annual cash incentives;

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

•	Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.

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

•	severance benefits under the Anadarko Officer Severance Plan;

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

•	director and officer indemnification agreements;

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

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

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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, 2016, 2015 and 2014. Ms. Dimpel’s amount reflects base salary compensation earned and allocated through April 8, 2016.

(2)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the 2012 Anadarko Omnibus Incentive Compensation Plans and include unvested amounts. For a discussion of valuation assumptions for the awards under the 2012 Anadarko Omnibus Incentive Compensation Plans, see Note 21—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, 2016 (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 2016, 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.

(3)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the 2012 Anadarko Omnibus Incentive Compensation Plans. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in 2016, see the Grants of Plan-Based Awards Table.

(4)

The amounts in this column reflect the compensation under the Anadarko annual incentive program expected to be allocated to us for the year ended December 31, 2016, and allocated to us for the years ended December 31, 2015 and 2014. The 2016 amounts represent payments which were earned in 2016 and are expected to be paid in early 2017, the 2015 amounts represent payments which were earned in 2015 and paid in early 2016 and the 2014 amounts represent the payments which were earned in 2014 and paid in early 2015. For an explanation of the 2016 annual incentive plan awards, read Compensation Discussion and Analysis – Analysis of 2016 Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses), contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than March 31, 2017.

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(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, 2016, 2015 and 2014. The 2016 allocated expenses are detailed in the table below:

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(1)

Reflects the estimated 2016 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 2016 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan, read Compensation Discussion and Analysis — Analysis of 2016 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than March 31, 2017.

(2)

Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in 2016. 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 specified performance period. The performance units granted to Messrs. Sinclair and Fink on November 10, 2016, are subject to 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 — Analysis of 2016 Compensation Actions — Equity Compensation contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than March 31, 2017.

(3)

Reflects the allocable number of restricted stock shares and restricted stock units awarded in 2016 under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. For restricted stock shares, dividends are paid current. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award. Also included are the 12,122 and 14,547 allocated special restricted stock units awarded in 2016 under the Omnibus Plan to Messrs. Sinclair and Fink, respectively, which will vest in four years from grant date, provided Messrs. Sinclair and Fink remain employed by Anadarko until such date.

(4)	Reflects the allocable number of Anadarko stock options each named executive officer was awarded in 2016. These awards vest equally over three years, beginning with the first anniversary of the date of grant 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 2016 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 21—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, 2016 (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)

The restricted stock units and shares will vest pro-rate annually over three years, beginning with the first anniversary of the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are converted into shares of unrestricted common stock, less applicable withholding taxes. For restricted stock shares, dividends are paid current. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. For the 12,122 and 14,547 allocated special restricted stock units received in November 2016 by Messrs. Sinclair and Fink, respectively, and their corresponding dividend unit equivalents, these will vest in four years from grant date, provided Messrs. Sinclair and Fink remain employed by Anadarko until such date.

(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, 2016, and are not necessarily indicative of what the payout percent earned will be at the end of each three year performance period. Anadarko’s relative performance ranking as of December 31, 2016 are: 128% for the 2013 grant, 100% for the 2014 grant, and 100% for the 2015 grant. For awards granted in 2016 with the performance period beginning in 2017, target payout has been assumed.

(1)	Shares acquired and values realized on exercise include options exercised in 2016. 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 2016 of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.

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(1)	As of December 31, 2016, Mr. Sinclair was eligible for retirement.

(2)

Under the terms of the performance unit agreements, retirement-eligible participants 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. However, the performance unit awards granted on November 10, 2016, are not included in the table above as the treatment described in the preceding sentence only applies to such awards if they have been held for at least 180 days after the grant date, which would not be the case in the event of a retirement that occurred on December 31, 2016. Mr. Sinclair’s value reflects an estimated payout based on performance to date through December 31, 2016, which is not indicative of the payout that he will receive at the end of the performance period based on actual performance.

(1)	Messrs. Sinclair’s and Fink’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of December 31, 2016. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(2)

Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink reflect the allocated portion of their actual bonuses awarded under the annual incentive plan. For additional discussion of this program, read Compensation Discussion and Analysis — Analysis of 2016 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than March 31, 2017. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(3)

Reflects the in-the-money value of unvested stock options (subject to Anadarko’s Board of Directors approval), the estimated current value of unvested performance units (based on performance to date) and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2016. In the event of an involuntary termination, unvested performance units would be paid after the end of the applicable performance period, based on actual performance. However, the performance unit awards and the restricted stock unit awards granted on November 10, 2016, are not included in the table above as accelerated vesting upon an involuntary not for cause termination only applies to such awards if they have been held for at least 180 days after the grant date, which would not be the case in the event of such a termination that occurred on December 31, 2016. 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. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2016.

(4)	Messrs. Sinclair’s and Fink’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentage in effect as of December 31, 2016. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

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(1)

Mr. Sinclair’s values and Mr. Fink’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of December 31, 2016, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(2)	Messrs. Sinclair’s and Fink’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(3)

Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2016. 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. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2016.

(4)

Under the terms of their change of control agreements, Messrs. Sinclair and Fink 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 they were 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 their allocation percentages in effect as of December 31, 2016, the expense would be as follows: Mr. Sinclair—$221,851 and Mr. Fink—$91,263.

(5)

Mr. Sinclair’s values and Mr. Fink’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of December 31, 2016, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.

(6)

Mr. Sinclair’s values and Mr. Fink’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of December 31, 2016. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(1)

Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2016. 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. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2016.

(2)	Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage in effect as of December 31, 2016.

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(1)	Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2016. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2016.

(2)

Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage in effect as of December 31, 2016, and exclude death benefit proceeds from programs available to all employees.

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

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

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

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

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

•	annual grants of phantom units with a value of approximately $90,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko). The non-employee directors received such a grant of phantom units on May 5, 2016.

(1)

The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2016, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. As of December 31, 2016, each of the non-employee directors had 1,826 outstanding phantom units.

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(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 2016 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.

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•	each member of the Board of Directors;

•	each named executive officer of our general partner;

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

•	Anadarko and its affiliates.

*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380. No person listed owns any Series A Preferred units.

(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 12,537,100 Class C units of the Partnership.

(3)

Does not include 1,826 unvested phantom units that were granted to each of Messrs. Carroll, Crane, Tudor, and Arnold under the WES LTIP. Phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our Board of Directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.

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

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*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380. No person listed owns any Series A Preferred units.

(2)	As of December 31, 2016, there were 559.0 million shares of Anadarko common stock issued and outstanding.

(3)

Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—32,833; Donald R. Sinclair—31,100; Benjamin M. Fink—25,016; Craig W. Collins—3,669; Darrell E. Hollek—29,552; and Robert K. Reeves—25,615; for a total of 147,785 unvested restricted stock units held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.

(4)

Includes 6,069 and 6,897 unvested shares of restricted common stock of Anadarko held by Philip H. Peacock and Craig W. Collins, 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/A filed February 13, 2017, with the SEC with respect to Partnership securities held as of December 31, 2016, Tortoise Capital Advisors, L.L.C. has shared voting power as to 11,046,458 common units and shared dispositive power as to 12,150,844 common units.

(2)	Based upon its Schedule 13G/A filed January 25, 2017, with the SEC with respect to Partnership securities held as of December 31, 2016, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 7,326,224 common units.

(1)	The Board of Directors adopted the WES LTIP in connection with the IPO of our common units.

(2)	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 2016); and

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

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

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

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

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

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

(3)

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

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

(5)	For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures and Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

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

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

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

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

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

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

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