Western Midstream Partners, LP - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

---

---

---

---

---

(1)	Includes the DBM water systems.

(1)	All system metrics are presented on a gross basis and include owned, rented, and leased compressors at certain facilities. Includes horsepower associated with liquid pump stations. Includes bypass capacity at the DJ Basin and West Texas complexes.

(2)	Excludes compression horsepower for transportation.

(3)	Includes throughput for all assets owned and ownership interests accounted for by us under the equity method of accounting. For further details see Properties below.

---

•

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

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

•

Controlling our operating, capital, and administrative costs. We continue to optimize and maximize the operability of our existing assets to realize cost and capital savings. As a result of the recent transformation of our workforce that historically maintained dual upstream and midstream responsibilities into a solely midstream-focused organization, we believe that we will drive operational, capital, and administrative cost efficiencies throughout the organization.

•

Maintaining investment grade metrics. We intend to operate with leverage metrics and distribution coverage levels that are consistent with other investment-grade credits in our sector. Maintaining leverage ratios that are within the industry-standard investment-grade credit metrics positions us to pursue strategic acquisitions and to fund large growth projects at a lower cost of capital, which enhances our accretion and overall return.

•	Managing commodity-price exposure. We intend to continue limiting our direct exposure to commodity-price changes and promote cash-flow stability by pursuing fee-based contract structures designed to mitigate direct exposure to commodity prices.

---

•

Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, which historically have 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 are capable of servicing hydrocarbon production that contains natural gas, crude oil, condensate, and NGLs. Our systems in the Delaware Basin also include significant produced-water takeaway capacity, which positions us as a full-service midstream provider in the basin.

•

Well-positioned and well-maintained assets. We believe that our asset portfolio, 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.

•

Commodity-price and volumetric-risk mitigation. We believe a substantial majority of our cash flows are protected from direct exposure to commodity-price volatility, as 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil, NGLs, and produced-water throughput (excluding equity investments) were serviced under fee-based contracts for the year ended December 31, 2019. In addition, we mitigate volumetric risk by entering into contracts with cost-of-service structures and/or minimum-volume commitments. For the year ended December 31, 2019, 65% of our natural-gas throughput and 78% of our crude-oil, NGLs, and produced-water throughput were supported by either minimum-volume commitments with associated deficiency payments or cost-of-service commitments.

•

Affiliation with Occidental. We believe Occidental is motivated to promote and support the successful execution of our business plan. We continue leveraging our long-standing relationship with Occidental by sizing and planning growth initiatives in a manner that highlights the strength of our asset portfolio vis a vis Occidental’s upstream development plans. Continuing our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business. See WES and WES Operating’s Relationship with Occidental Petroleum Corporation below.

•

Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-dated debt maturity profile, long-term relationships, and reasonable access to 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, 2019, there was $1.6 billion in available borrowing capacity under the RCF.

---

---

•

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

•

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

•

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 or hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide or hydrogen sulfide from the gas stream.

•

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

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

•

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

•

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 downstream 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 the onshore production of crude oil and natural gas. Produced-water gathering assets provide the link between well sites or nearby collection points and disposal facilities.

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

---

•

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

•

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

•

Keep-whole. Keep-whole arrangements may be used for processing services. Under these arrangements, a customer provides liquids-rich gas volumes to the service provider for processing. The service provider is obligated to return the equivalent gas volumes to the customer subsequent to processing. Due to the use and loss of volumes in processing, the service provider must purchase additional volumes to compensate the customer. In these arrangements, the service provider receives all or a portion of the NGLs produced in consideration for the service provided. These types of arrangements expose the service provider to commodity-price exposure associated with the cost of purchased keep-whole volumes and the sales value of the retained NGLs.

---

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

(2)	Includes 12 miles of transportation related to a crude-oil pipeline at the DJ Basin oil system.

(3)	The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT (currently inactive), Wattenberg, Lancaster Trains I and II, and Latham Train I processing plants, and the Wattenberg gathering system. Excludes 600 gpm of amine-treating capacity.

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

---

•

Customers. For the year ended December 31, 2019, Occidental’s production represented 62% of the DJ Basin complex throughput and the two-largest third-party customers provided 19% of the throughput. Effective December 31, 2019, Kerr-McGee Oil & Gas Onshore, LP, a subsidiary of Occidental, and Kerr-McGee Gathering LLC (“KMGG”), a subsidiary of WES Operating, entered into an amendment to the DJ gas-gathering agreement to provide for the extension of gathering services by KMGG to gas produced by a subsidiary of Occidental in Weld County, Colorado, in the DJ Basin for a primary term ending August 2029. This agreement provides new acreage dedications covering approximately 21,000 acres.

•	Supply. The DJ Basin complex is supplied primarily by the Wattenberg field. There were 1,806 active receipt points connected to the DJ Basin complex as of December 31, 2019. Occidental has dedicated to WES approximately 640,000 gross acres within the DJ Basin.

•

Delivery points. As of December 31, 2019, the DJ Basin complex had various delivery-point interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system for gas not processed within the DJ Basin complex. The DJ Basin complex is connected to the Colorado Interstate Gas Company LLC’s pipeline (“CIG pipeline”) and Xcel Energy’s residue pipelines for natural-gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline and FRP’s pipeline for NGLs takeaway. In addition, the NGLs fractionator at the Platte Valley plant and associated truck-loading facility provides access to local NGLs markets.

•	Customers. For the year ended December 31, 2019, all of the DJ Basin oil system throughput was from Occidental’s production.

•	Supply. The DJ Basin oil system, which is supplied primarily by the Wattenberg field, gathers high-vapor-pressure crude oil and delivers it to the COSF. The COSF includes two 250,000 barrel crude-oil storage tanks and connectivity to local storage owned by Energy Transfer LP (“ET”).

•	Delivery points. The COSF has market access to the White Cliffs pipeline, Saddlehorn pipeline, and rail-loading facilities in Tampa, Colorado, and local markets.

---

•	Customers. For the year ended December 31, 2019, Occidental’s production represented 66% of the Chipeta complex throughput and the two largest third-party customers provided 27% of the throughput.

•

Supply. The Chipeta complex is well positioned to access Occidental and third-party production in the Uinta Basin. Occidental has dedicated to WES approximately 170,000 gross acres in the Uinta Basin. Chipeta’s inlet is connected to Occidental’s Greater Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”), and Three Rivers Gathering, LLC’s system, which is owned by MPLX LP (“MPLX”).

•

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

◦	CIG pipeline;

◦	Questar pipeline; and

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

---

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

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

(3)	The Red Desert complex includes the Red Desert cryogenic processing plant, which currently is 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. Bison treating facility throughput was from one third-party customer as of December 31, 2019. In connection with Anadarko’s sale of the Powder River Basin coal-bed methane assets in 2015, Occidental still retains a commitment to Bison that extends through December 2020 for which we earn affiliate revenues.

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

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

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

◦	CIG pipeline;

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

◦	WIC pipeline.

•	Customers. As of December 31, 2019, gas gathered and processed at the Hilight system was from third-party customers. The four-largest producers provided 70% of the system throughput for the year ended December 31, 2019.

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

---

•	Customers. As of December 31, 2019, Granger complex throughput was from third-party customers, with the three-largest third-party customers providing 77% of the Granger complex throughput for the year ended December 31, 2019.

•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas-gathering system had 580 active receipt points as of December 31, 2019.

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

◦	CIG pipeline;

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

◦	Questar pipeline;

◦	Dominion Energy Overthrust Pipeline;

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

◦	our OTTCO pipeline; and

◦	our Mountain Gas Transportation LLC pipeline.

•	Customers. For the year ended December 31, 2019, 70% of the Red Desert complex throughput was from the four-largest third-party customers and 1% was from Occidental.

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

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

•	Customers. As of December 31, 2019, Rendezvous system throughput primarily was from two shippers that have dedicated acreage to the system.

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

---

(1)	Includes 70 MMcf/d of bypass capacity at the West Texas complex.

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

(3)	Includes 18 miles of transportation related to the Ramsey Residue Lines (regulated by FERC) at the West Texas complex and 14 miles of transportation related to a crude-oil pipeline at the DBM oil system.

(4)	The West Texas complex includes the DBM complex and DBJV and Haley systems. Excludes 2,300 gpm of amine-treating capacity.

(5)	The DBM oil system includes three central production facilities and two ROTFs.

(6)	We own a 50% interest in Mi Vida, which owns a processing plant operated by a third party.

(7)	We own a 50% interest in Ranch Westex, which owns a processing plant operated by a third party.

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

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

---

•	Customers. For the year ended December 31, 2019, Occidental’s production represented 41% of the West Texas complex throughput and the largest third-party customer provided 10% of the throughput.

•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring, Wolfcamp, and Penn formations in the Delaware Basin portion of the Permian Basin. Occidental has dedicated to WES approximately 530,000 gross acres within the Delaware Basin.

•

Delivery points. Avalon, Bone Spring, and Wolfcamp gas is dehydrated, compressed, and delivered to the Ranch Westex and Mi Vida plants (see below) and within the West Texas complex for processing, while lean gas is delivered into Enterprise GC, L.P.’s pipeline for ultimate delivery into ET’s Oasis pipeline (the “Oasis pipeline”). Residue gas from the West Texas complex is delivered to the Red Bluff Express pipeline and the Ramsey Residue Lines, which extend from the complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system. NGLs production is delivered into the Sand Hills pipeline, Lone Star NGL LLC’s pipeline (“Lone Star pipeline”), and EPIC Y-Grade Pipeline, LP’s NGL pipeline.

---

•	Customers. As of December 31, 2019, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2019, Occidental’s production represented 94% of the DBM oil system throughput. All parties ship pursuant to a tariff on file with the Texas Railroad Commission.

•	Supply. The DBM oil system is supplied from production from the Delaware Basin portion of the Permian Basin.

•	Delivery points. Crude oil treated at the DBM oil system and a third-party treating facility is delivered from the system into Plains All American Pipeline.

•	Customers. As of December 31, 2019, DBM water systems throughput was from Occidental and numerous third-party producers. Occidental’s production represented 82% of the throughput for the year ended December 31, 2019.

•	Supply. Supply of produced water for the systems comes from crude-oil production from the Delaware Basin portion of the Permian Basin.

•	Disposal. The DBM water systems gather and dispose produced water via subsurface injection or offload to third-party service providers. The systems’ injection wells are located in Loving, Reeves, and Ward Counties in Texas.

•	Customers. As of December 31, 2019, Mi Vida plant throughput was from Occidental and one third-party customer.

•	Supply and delivery points. The Mi Vida plant receives volumes from the West Texas complex and ET’s gathering system. Residue gas from the Mi Vida plant is delivered to the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”). NGLs production is delivered to the Lone Star pipeline.

•	Customers. As of December 31, 2019, Ranch Westex plant throughput was from Occidental and one third-party customer.

•	Supply and delivery points. The Ranch Westex plant receives volumes from the West Texas complex and Crestwood Equity Partners LP’s gathering system. Residue gas from the Ranch Westex plant is delivered to the Oasis pipeline or Transwestern pipeline and NGLs production is delivered to the Lone Star pipeline.

---

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

•

Supply and delivery points. Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline, TEP, and Panola pipeline (see Transportation within these Items 1 and 2). Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminals.

---

•	Customers. Brasada complex throughput was from one third-party customer as of December 31, 2019.

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

•	Delivery points. The facility delivers residue gas to the Eagle Ford Midstream system operated by NET Midstream, LLC. Stabilized condensate is delivered to Plains All American Pipeline and NGLs are delivered to the Enterprise-operated South Texas NGL Pipeline System.

•	Customers. Springfield system throughput was from numerous third-party customers as of December 31, 2019.

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

•

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

---

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

•	Customers. As of December 31, 2019, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided 80% of the throughput for the year ended December 31, 2019. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC.

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

---

---

(1)	White Cliffs, Saddlehorn, GNB NGL, MIGC, FRP, TEP, Panola, Cactus II, and Red Bluff Express 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 the Saddlehorn pipeline, which is operated by a third party.

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

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

(6)	We own a 15% interest in the Panola pipeline, which is operated by a third party.

(7)	We own a 15% interest in the Cactus II pipeline, which is operated by a third party.

(8)	We own a 30% interest in the Red Bluff Express pipeline, which is operated by a third party.

•

Customers. The White Cliffs pipeline had multiple committed shippers, including Occidental, as of December 31, 2019. Other parties may also ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual-pipeline system provides crude-oil and NGL takeaway capacity of approximately 190 MBbls/d from Platteville, Colorado, to Cushing, Oklahoma. In 2019, one of the pipelines was converted from crude-oil service to NGL Y-grade service.

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

•	Delivery points. The White Cliffs pipeline delivery point is ET’s storage facility in Cushing, Oklahoma, a major crude-oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries.

•	Customers. The Saddlehorn pipeline had multiple committed shippers, including Occidental, as of December 31, 2019. Other parties may also ship on the Saddlehorn pipeline at FERC-based rates.

•	Supply. The Saddlehorn pipeline has multiple origin points including: Cheyenne, Wyoming; Ft. Laramie, Wyoming; Carr, Colorado; and Platteville, Colorado. Saddlehorn is supplied by the DJ Basin and basins that connect to a Wyoming access point.

•	Delivery points. The Saddlehorn pipeline delivers crude oil and condensate to storage facilities in Cushing, Oklahoma.

---

•	Customers. Occidental was the only shipper on the GNB NGL pipeline as of December 31, 2019. The GNB NGL pipeline provides capacity at the posted FERC-based rates.

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

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

•	Customers. Occidental was the largest firm shipper on the MIGC system, with 56% of the throughput for the year ended December 31, 2019. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm-transportation capacity. All parties on the MIGC system ship pursuant to a tariff on file with FERC.

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

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

◦	CIG pipeline;

◦	TIGT pipeline; and

◦	WIC pipeline.

•	Customers. For the year ended December 31, 2019, 8% of OTTCO’s throughput was from Occidental. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contracts that contain minimum-volume commitments and volumetric fees paid by shippers under firm and interruptible gas-transportation agreements.

•

Supply and delivery points. Supply points to the OTTCO transportation system include approximately 28 active 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.

---

•	Customers. For the year ended December 31, 2019, 93% of the Wamsutter pipeline throughput was from two third-party shippers, with the remaining throughput from Occidental. Revenues on the Wamsutter pipeline are generated from tariff-based rates regulated by the Wyoming Public Service Commission.

•	Supply and delivery points. The Wamsutter pipeline has two active receipt points in Sweetwater County, Wyoming, and delivers crude oil to MPLX LP’s SLC Core Pipeline System.

•

Front Range Pipeline. FRP provides NGLs takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld and Adams Counties, Colorado (including the Lancaster and Wattenberg plants, which are within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2019, FRP had multiple committed shippers, including Occidental. FRP provides capacity to other shippers at the posted FERC tariff rate. In 2018, we elected to participate in the expansion of FRP, which is ongoing and expected to be completed in 2020. The expansion of FRP will increase its capacity by 100 MBbls/d, to a targeted total capacity of approximately 260 MBbls/d.

•	Texas Express Gathering. TEG consists of two NGLs gathering systems that provide plants in North Texas, the Texas panhandle, and West Oklahoma with access to NGLs takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2019.

•

Texas Express Pipeline. TEP delivers to NGLs fractionation and storage facilities in Mont Belvieu, Texas. TEP is supplied with NGLs from other pipelines including FRP, the MAPL pipeline, and TEG. As of December 31, 2019, TEP had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates. In 2018, we elected to participate in the expansion of TEP. The expansion was completed in November 2019 and increased capacity by 90 MBbls/d, to a total capacity of approximately 350 MBbls/d.

•	Customers. As of December 31, 2019, the Cactus II pipeline had multiple committed shippers, including Occidental. The Cactus II pipeline also provides capacity to other shippers at the posted FERC-based rates.

•	Supply. The Cactus II pipeline is supplied by production from McCamey, Texas, and leases capacity on Plains All American Pipeline, L.P.’s intra-Delaware Basin pipelines to allow for origin points in Orla, Wink, Midland, and Crane, Texas.

•	Delivery points. The Cactus II pipeline transports crude oil from West Texas to the Corpus Christi, Texas, area. Primary delivery points in Corpus Christi include the Plains All American Pipeline; Nustar Energy, L.P.; Moda Ingleside Energy Center; and Buckeye Partners, L.P.’s export terminals.

---

•	Customers. As of December 31, 2019, the Red Bluff Express pipeline had multiple committed shippers, including Occidental. The Red Bluff Express pipeline also provides capacity to other shippers at the posted FERC-based rates.

•	Supply and delivery points. The Red Bluff Express pipeline is supplied by production from (i) our Ramsey and Mentone gas-processing plants that are part of the West Texas complex and (ii) other third-party plants. The Red Bluff Express pipeline transports natural gas from Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas.

•	Latham Train II. As of December 31, 2019, we were constructing a second cryogenic train at the Latham processing plant at the DJ Basin complex. Latham Train II commenced operation in February 2020 with a capacity of 200 MMcf/d. Upon completion of Latham Train II, the DJ Basin complex has a total processing capacity of 1,680 MMcf/d.

•

Loving ROTF Trains III and IV. We currently are commissioning and constructing two additional oil-stabilization trains at the ROTFs (part of the DBM oil system). Loving ROTF Trains III and IV will have capacities of 30 MBbls/d each. Construction of Loving ROTF Train III was complete in the fourth quarter of 2019 and commenced operation in January 2020. Loving ROTF Train IV is expected to be completed in the fourth quarter of 2020. Upon completion, the DBM oil system will have a total processing capacity of 255 MBbls/d.

---

---

•	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.

---

---

---

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

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

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

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

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

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

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

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

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

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

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

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

---

---

---

•	our ability to pay distributions to our unitholders;

•	our assumptions about the energy market;

•	future throughput (including Occidental production) that is gathered or processed by, or transported through our assets;

•	our operating results;

•	competitive conditions;

•	technology;

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

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

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

•	weather and natural disasters;

•	inflation;

•	the availability of goods and services;

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

•	federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations;

•	environmental liabilities;

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

•	changes in the financial or operational condition of Occidental;

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

---

•	changes in Occidental’s capital program, corporate strategy, or other desired areas of focus;

•	our commitments to capital projects;

•	our ability to access liquidity under the RCF;

•	our ability to repay debt;

•	conflicts of interest among us, our general partner and its affiliates, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;

•	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 third parties;

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

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

•	the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; and

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

---

•	the volatility of oil and natural-gas prices, which could have a negative effect on the value of Occidental’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 Occidental’s exploration and development activities;

•	a reduction in or reallocation of Occidental’s capital budget, which could reduce the gathering, transportation, and treating volumes available to us as a midstream operator, and/or limit our opportunities for organic growth;

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

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

---

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

•	transportation-capacity constraints and interruptions;

•	adverse effects of governmental and environmental regulation, including state-approved ballot initiatives that would change state constitutions or statutes in a manner that makes future oil and gas development in such states more difficult or expensive;

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

•	adverse effects from current or future litigation.

•	implementing technology systems to manage the operations and administration of our day-to-day business;

•	maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002;

•	replicating regulatory compliance and governance infrastructure:

•	hiring, training, or retaining qualified personnel as needed to replace positions that have previously been provided as a shared service by Occidental;

•	identifying and filling gaps in management functions and expertise and establishing effective communication and information exchange among management teams and employees;

•	diverting management’s attention from our existing business; and

•	potentially losing business or key employees.

---

•	domestic and worldwide economic and geopolitical conditions;

•	weather conditions and seasonal trends;

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

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

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

•	the availability of transportation systems with adequate capacity;

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

•	the price and availability of alternative fuels;

•	the effect of energy conservation measures;

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

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

---

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

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

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

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

•	the level of competition from other midstream companies;

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

•	prevailing economic conditions.

---

•	our level of capital expenditures;

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

•	our debt-service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

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

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

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

---

---

---

•	incur additional indebtedness or guarantee other indebtedness;

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

•	engage in transactions with affiliates;

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

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

•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or 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.

---

---

---

---

•

Ground-Level Ozone Standards. In 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable,” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

---

•

Reduction of Methane Emissions by the Oil and Gas Industry. In 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed amendments that included rescission or revision of specified rule requirements, such as fugitive emission monitoring frequency. In August 2019, the EPA proposed two options for rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed, and modified oil and natural-gas production sources while leaving in place the general emission limits for volatile organic compounds (“VOCs”) and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural-gas category the natural-gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the NSPS applicable to all oil and natural-gas sources, without removing any sources from that category (and still requiring control of VOCs in general). In a separate rulemaking, the BLM published a final rule in late 2016 that requires a reduction in methane emissions by regulating venting, flaring, and leaking from oil and natural-gas operations on public lands; however, in September 2018, the BLM published a final rule rescinding most of the new requirements of the 2016 final rule and codifying the BLM’s prior approach to venting and flaring, which rescission has been challenged in federal court and remains pending. Notwithstanding the uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural-gas exploration and production operators, to reduce methane emissions. At the state level, some states where we conduct operations, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.

•

Reduction of GHG Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG-reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement, and in November 2019 the United States formally initiated the withdrawal process. The implementation of substantial limitations on GHG emissions in areas where we conduct operations could result in increased compliance costs to acquire emissions allowances or comply with new regulatory or reporting requirements, which developments could adversely affect demand for oil and natural gas that our customers produce, reduce demand for our services, and have a material adverse effect on our business, financial condition, and results of operation.

---

---

---

---

---

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

•	inadvertent damage from construction, farm, and utility equipment;

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

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

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

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

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

---

•	the assumption of unknown liabilities, including environmental liabilities;

•	limitations on rights to indemnity from the seller;

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

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

•	unforeseen difficulties operating in new geographic areas; and

•	customer or key employee losses at the acquired businesses.

---

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

•	Occidental 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 Occidental, in resolving conflicts of interest.

•	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 may cause us to borrow funds in order to permit the payment of cash distributions.

•	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.

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

---

---

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

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

•	whether to exercise its registration rights; and

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

•

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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

•

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.

---

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

•	the amount of per-unit cash available for distribution 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.

---

•	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.

---

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

•	the public’s reaction to Occidental’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.

---

---

---

---

---

---

---

(1)	See Property exchange below.

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

---

(1)

For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

---

---

(1)	Includes the DBM water systems.

---

•

Exchange Agreement. WGRI, the general partner, and WES entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which WES canceled the non-economic general partner interest in WES and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 WES common units to WES, which immediately canceled such units on receipt.

•

Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into the Services Agreement, pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to WES for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to WES and WES’s assumption of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES for anticipated transition costs required to establish stand-alone human resources and information technology functions.

•

RCF amendment. WES Operating entered into an amendment to its RCF to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.

•

Term loan facility amendment. WES Operating entered into an amendment of its Term loan facility to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.

•	Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.

•	Termination of omnibus agreements. WES and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information on the WES and WES Operating omnibus agreements.

---

•	We increased our per-unit distribution to $0.62200 for the fourth quarter of 2019, representing a 0.3% increase over the third-quarter 2019 distribution and a 3% increase over the fourth-quarter 2018 distribution.

•

In July 2019, WES Operating entered into an amendment to the Term loan facility to (i) extend the maturity date from February 2020 to December 2020, and (ii) increase commitments available under the Term loan facility from $2.0 billion to $3.0 billion, the incremental $1.0 billion of which was subsequently drawn by WES Operating on September 13, 2019, and used to repay outstanding borrowings under the RCF. In December 2019, WES Operating amended certain provisions of the Term loan facility. See Liquidity and Capital Resources within this Item 7 for additional information.

•

In March 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $375.0 million. In November and December 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $1,125.0 million, effectively offsetting those entered into in December 2018 and March 2019. In December 2019, all outstanding interest-rate swap agreements were cash-settled. See Liquidity and Capital Resources within this Item 7 for additional information.

•	In March 2019, the WGP RCF matured and the outstanding borrowings were repaid. See Liquidity and Capital Resources within this Item 7 for additional information.

---

•	We commenced operations of Mentone Train II at the West Texas complex (with capacity of 200 MMcf/d) and Latham Train I at the DJ Basin complex (with capacity of 200 MMcf/d) at the end of the first and fourth quarters, respectively, of 2019.

•

In February 2019, WES Operating increased the size of the RCF from $1.5 billion to $2.0 billion and extended the maturity date of the RCF to February 2024. In December 2019, WES Operating extended the maturity date of the RCF to February 2025 for the extending lenders and modified the change of control definition in the RCF. See Liquidity and Capital Resources within this Item 7 for additional information.

•	In January 2019, we acquired a 30% interest in Red Bluff Express from a third party. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

•	Natural-gas throughput attributable to WES totaled 4,248 MMcf/d for the year ended December 31, 2019, representing a 9% increase compared to the year ended December 31, 2018.

•	Crude-oil, NGLs, and produced-water throughput attributable to WES totaled 1,195 MBbls/d for the year ended December 31, 2019, representing a 57% increase compared to the year ended December 31, 2018.

•	Operating income (loss) was $1,231.3 million for the year ended December 31, 2019, representing a 43% increase compared to the year ended December 31, 2018.

•	Adjusted gross margin for natural-gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.07 per Mcf for the year ended December 31, 2019, representing a 6% increase compared to the year ended December 31, 2018.

•	Adjusted gross margin for crude-oil, NGLs, and produced-water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.77 per Bbl for the year ended December 31, 2019, representing an 8% decrease compared to the year ended December 31, 2018.

---

---

---

•	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.

---

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

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

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

---

---

(1)

For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

(1)

For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2)	Excludes net non-cash losses on interest-rate swaps of $25.6 million and $8.0 million for the years ended December 31, 2019 and 2018, respectively. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

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

(2)

For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within 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)	For the year ended December 31, 2019, excludes cash payments of $107.7 million related to the settlement of interest-rate swap agreements. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)	Reflects cash distributions of $2.47000 per unit declared for the year ended December 31, 2019, including the cash distribution of $0.62200 per unit paid on February 13, 2020, for the fourth-quarter 2019 distribution.

---

---

---

(1)

Revenues and other include amounts earned from services provided to our affiliates and from the sale of residue gas and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services and reimbursements of amounts paid by affiliates to third parties on our behalf. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

(3)	For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.

(4)

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

---

(1)	The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now is referred to as the “West Texas complex,” and resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating, and transportation” now being reported as “Processing.”

(2)	Represents the 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput.

(3)

For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)	Represents the 10% share of average White Cliffs throughput; 25% share of average Mont Belvieu JV throughput; 20% share of average TEG, TEP, Whitethorn, and Saddlehorn throughput; 33.33% share of average FRP throughput; and 15% share of average Panola and Cactus II throughput.

---

---

---

(1)

For the years ended December 31, 2018 and 2017, includes the effects of commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

(1)

For the year ended December 31, 2017, includes the effects of the commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

---

(1)	Includes general and administrative expenses incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets.

---

---

---

(1)	Adjusted gross margin is calculated as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from our equity investments, and excluding the noncontrolling interests owners’ proportionate share of revenues and cost of product.

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

(3)	Average for period. Calculated as Adjusted gross margin for natural-gas assets, divided by total throughput (MMcf/d) attributable to WES for natural-gas assets.

(4)	Average for period. Calculated as Adjusted gross margin for crude-oil, NGLs, and produced-water assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil, NGLs, and produced-water assets.

---

---

---

•

maintenance capital expenditures, which include those expenditures required to maintain 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 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.

(1)	For the years ended December 31, 2019, 2018, and 2017, included $23.3 million, $31.1 million, and $9.1 million, respectively, of capitalized interest. For the years ended December 31, 2018 and 2017, capitalized interest included $9.0 million and $2.2 million, respectively, of pre-acquisition capitalized interest for AMA.

(2)	Capital expenditures for the years ended December 31, 2018 and 2017, included $762.8 million and $353.3 million, respectively, of pre-acquisition capital expenditures for AMA. Capital expenditures for the year ended December 31, 2017, are presented net of $1.4 million of contributions in aid of construction costs from affiliates.

(3)	Capital incurred for the years ended December 31, 2018 and 2017, included $733.1 million and $453.4 million, respectively, of pre-acquisition capital incurred for AMA.

---

•	$2.0 billion of cash paid for the acquisition of AMA;

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

•	$128.4 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for construction activities;

•	$92.5 million of cash paid for the acquisition of our interest in Red Bluff Express; and

•	$30.3 million of distributions received from equity investments in excess of cumulative earnings.

•	$1.9 billion of capital expenditures, primarily related to construction and expansion at the DBM oil and DBM water systems and the West Texas and DJ Basin complexes;

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

•	$133.6 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Whitethorn LLC, and White Cliffs for construction activities; and

---

•	$29.6 million of distributions received from equity investments in excess of cumulative earnings.

•	$1.0 billion of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBJV system, DBM complex, DBM oil system, and DJ Basin complex and the construction of the DBM water systems;

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

•	$22.5 million of cash paid for the acquisition of the additional interest in Ranch Westex;

•	$3.9 million of cash paid for equipment purchases from affiliates;

•	$31.7 million of distributions received from equity investments in excess of cumulative earnings;

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

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

•	$3.0 billion of borrowings under the Term loan facility, net of issuance costs, which were used to fund the acquisition of AMA, repay the APCWH Note Payable, and repay amounts outstanding under the RCF;

•	$1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including to fund capital expenditures;

•	$458.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

•	$11.0 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;

•	$7.4 million of capital contributions from Anadarko related to the above-market component of swap agreements;

•	$1.0 billion of repayments of outstanding borrowings under the RCF;

•	$969.1 million of distributions paid to WES unitholders;

•	$439.6 million of repayments of the total outstanding balance under the APCWH Note Payable;

•	$118.2 million of distributions paid to the noncontrolling interest owners of WES Operating;

•	$28.0 million of repayments of the total outstanding balance under the WGP RCF, which matured in March 2019; and

•	$9.7 million of distributions paid to the noncontrolling interest owner of Chipeta.

---

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

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

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

•	$321.8 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;

•	$97.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

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

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

•	$502.5 million of distributions paid to WES unitholders;

•	$386.3 million of distributions paid to the noncontrolling interest owners of WES Operating;

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

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

•	$3.4 million of issuance costs incurred in connection with the Term loan facility.

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

•	$126.9 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

•	$98.8 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;

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

•	$442.0 million of distributions paid to WES unitholders;

•	$355.6 million of distributions paid to the noncontrolling interest owners of WES Operating;

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

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

---

---

---

(1)

Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. As of December 31, 2019, 2018, and 2017, the public held a 0%, 59.2%, and 59.6% limited partner interest in WES Operating, respectively. Certain subsidiaries of Occidental separately held a 2.0%, 9.7%, and 9.1% limited partner interest in WES Operating as of December 31, 2019, 2018, and 2017, respectively. Immediately prior to the Merger closing, the WES Operating IDRs and the general partner units were converted into a non-economic general partner interest in WES Operating and WES Operating common units, and at Merger completion, all WES Operating common units held by the public and subsidiaries of Anadarko (other than common units held by WES, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into WES common units. 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.

(2)	Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

---

(1)	Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

(2)	Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(3)	Difference attributable to elimination upon consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

---

---

---

---

---

---

---

---

---

---

---

(1)

Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5 million, and $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $101.5 million, $49.7 million, and $43.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.

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

(3)	Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.

(4)	Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.

(5)	See Note 1.

---

(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.3 million and $72.6 million as of December 31, 2019 and 2018, respectively.

(2)	Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.

(3)	Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.

(4)	As of December 31, 2019, all amounts are considered affiliate. See Note 14.

(5)	Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.

(6)	See Note 1 and Note 6.

(7)	Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.

(8)	See Note 1.

---

(1)	See Note 6.

(2)	For the years ended December 31, 2019, 2018, and 2017, the $(755.2) million, $(19.6) million, and $6.6 million increase (decrease) to partners’ capital, respectively, together with net income (loss) attributable to Western Midstream Partners, LP, totaled $(58.0) million, $532.0 million, and $547.4 million, respectively.

(3)	See Note 3.

(4)	Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.

(5)	See Note 1.

(6)	The amounts allocated to common unitholders and noncontrolling interests represent a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.

---

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

(2)	For the years ended December 31, 2019 and 2018, includes $11.0 million and $321.8 million of borrowings, respectively, under the APCWH Note Payable.

(3)	For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.

(4)	See Note 3.

(5)	See Note 6.

---

---

(1)

Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5 million, and $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $99.6 million, $48.8 million, and $42.4 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.

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

(3)	Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.

(4)	Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.

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

---

(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.6 million and $72.8 million as of December 31, 2019 and 2018, respectively.

(2)	Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.

(3)	Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.

(4)	As of December 31, 2019, all amounts are considered affiliate. See Note 14.

(5)	Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.

(6)	See Note 1 and Note 6.

(7)	Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.

(8)	Immediately prior to the closing of the Merger (as defined in Note 1), all outstanding general partner units converted into a non-economic general partner interest in WES Operating and WES Operating common units and all outstanding Class C units converted into WES Operating common units on a one-for-one basis.

---

(1)	See Note 6.

(2)	See Note 5.

(3)	See Note 3.

(4)	Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.

(5)	See Note 1.

(6)	The amount allocated to common unitholders represents a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.

---

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

(2)	For the years ended December 31, 2019 and 2018, includes $11.0 million and $321.8 million of borrowings, respectively, under the APCWH Note Payable.

(3)	For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.

(4)	See Note 3.

(5)	See Note 6.

---

(1)	Includes the DBM water systems.

---

•

Exchange Agreement. Western Gas Resources, Inc. (“WGRI”), the general partner, and the Partnership entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which the Partnership canceled the non-economic general partner interest in the Partnership and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 common units to the Partnership, which immediately canceled such units on receipt.

•

Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into an amended and restated Services, Secondment, and Employee Transfer Agreement (the “Services Agreement”), pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to the Partnership for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to the Partnership and the assumption by the Partnership of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to the Partnership for anticipated transition costs required to establish stand-alone human resources and information technology functions.

•

RCF amendment. WES Operating entered into an amendment to its $2.0 billion senior unsecured revolving credit facility (“RCF”) to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.

•

Term loan facility amendment. WES Operating entered into an amendment of its $3.0 billion senior unsecured credit facility (“Term loan facility”) to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.

•	Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.

•	Termination of omnibus agreements. The Partnership and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6.

---

---

(1)	The 25% third-party interest in Chipeta Processing LLC (“Chipeta”) is reflected within noncontrolling interests in the consolidated financial statements, in addition to the noncontrolling interests noted below.

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

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

---

---

---

---

---

---

---

---

---

---

•	Wattenberg processing plant. The Wattenberg processing plant consists of a cryogenic train (with capacity of 190 million cubic feet per day (“MMcf/d”)) and a refrigeration train (with capacity of 80 MMcf/d) located in Adams County, Colorado, now part of the DJ Basin complex.

•	Wamsutter pipeline. The Wamsutter pipeline is a crude-oil gathering pipeline located in Sweetwater County, Wyoming and delivers crude oil into MPLX LP’s SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System).

•

DJ Basin oil system. The DJ Basin oil system consists of (i) a crude-oil gathering system, (ii) a centralized oil stabilization facility (“COSF”), and (iii) a 12-mile crude-oil pipeline, located in Weld County, Colorado. The COSF consists of Trains I through VI with total capacity of 155 thousand barrels per day (“MBbls/d”) and two storage tanks with total capacity of 500,000 barrels. Train VI commenced operations in 2018. The pipeline connects the COSF to Tampa Rail.

•

DBM oil system. The DBM oil system consists of (i) a crude-oil gathering system, (ii) three central production facilities (“CPFs”), which include ten processing trains with total capacity of 75 MBbls/d, (iii) three storage tanks with total capacity of 30,000 barrels, (iv) a 14-mile crude-oil pipeline, and (v) two regional oil treating facilities (“ROTFs”), which include four trains with total capacity of 120 MBbls/d, located in Reeves and Loving Counties, Texas. The ROTFs commenced operations in 2018. The pipeline transports crude oil from the DBM oil system and one third-party CPF into Plains All American Pipeline.

•	APC water systems. The APC water systems consist of five produced-water disposal systems with total capacity of 565 MBbls/d, located in Reeves, Loving, and Ward Counties, Texas, which are now part of the DBM water systems. One produced-water disposal system commenced operations in 2017 and the other four commenced operations in 2018.

---

•

A 20% interest in Saddlehorn. Saddlehorn owns (i) a crude-oil and condensate pipeline (excluding pipeline capacity leased by Saddlehorn) that originates in Laramie County, Wyoming, and terminates in Cushing, Oklahoma, and (ii) four storage tanks with total capacity of 300,000 barrels. The Saddlehorn interest is accounted for under the equity method of accounting and the pipeline is operated by a third party.

•	A 15% interest in Panola. Panola owns a 248-mile NGLs pipeline that originates in Panola County, Texas, and terminates in Mont Belvieu, Texas. The Panola interest is accounted for under the equity method of accounting and the pipeline is operated by a third party.

•	A 50% interest in Mi Vida. Mi Vida owns a cryogenic gas processing plant (with capacity of 200 MMcf/d) located in Ward County, Texas. The interest in Mi Vida is accounted for under the equity method of accounting and the processing plant is operated by a third party.

•	A 50% interest in Ranch Westex. Ranch Westex owns a processing plant consisting of a cryogenic train (with capacity of 100 MMcf/d) and a refrigeration train (with capacity of 25 MMcf/d), located in Ward County, Texas. The interest in Ranch Westex is accounted for under the equity method of accounting and the processing plant is operated by a third party.

---

(1)	The 2017 and 2018 distributions were declared and paid prior to the closing of the Merger.

(2)	The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2019 of $0.62200 per unit, or $281.8 million in aggregate. The cash distribution was paid on February 13, 2020, to unitholders of record at the close of business on January 31, 2020, including the general partner units that were issued on December 31, 2019 (see Note 1).

---

---

(1)	Total Partnership units issued at Merger completion exceeds the calculation of such units using the exchange ratio due to the rounding convention described in the Merger Agreement.

---

(1)	All WES Operating common units that converted into the Partnership’s common units at closing of the Merger were canceled and an equivalent amount of the canceled WES Operating common units were issued to the Partnership. See Note 1 for further details on the units issued and converted in connection with the closing of the Merger.

---

---

---

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

(2)

The impact of Class C units would be anti-dilutive for the periods presented and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

---

---

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

---

---

---

(1)	At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.

---

(1)	At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.

---

(1)	Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.

(2)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to the Partnership by Occidental (see LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.

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

(4)	Includes amounts related to finance leases and the APCWH Note Payable (see Note 1 and Note 13).

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

(6)	Represents distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).

(7)	Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).

(1)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.

(2)	Represents distributions paid to the Partnership and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5). For the year ended December 31, 2019, includes distributions to the Partnership and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13).

---

---

---

---

(1)	Includes capitalized interest of $1.4 million and $3.6 million for the years ended December 31, 2018 and 2019, respectively, related to the construction of the Cactus II pipeline.

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

---

---

(1)	Includes amounts related to WES Operating’s interest-rate swap agreements as of December 31, 2019 and 2018 (see Note 13). Includes lease liabilities related to the implementation of ASU 2016-02, Leases (Topic 842) as of December 31, 2019 (see Note 1).

---

---

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

(2)	Amounts are considered affiliate. See Note 14.

---

---

---

---

(1)	Includes additions to ROU assets and lease liabilities of $8.5 million related to finance leases for the year ended December 31, 2019.

---

---

•

$1.0 billion in aggregate principal amount of 3.100% Senior Notes due 2025, $1.2 billion in aggregate principal amount of 4.050% Senior Notes due 2030, and $1.0 billion in aggregate principal amount of 5.250% Senior Notes due 2050, offered to the public at prices of 99.962%, 99.900%, and 99.442%, respectively, of the face amount (collectively referred to as the “Senior Notes”). Interest is paid on each such series semi-annually on February 1 and August 1 of each year, beginning August 1, 2020; and

•

$300.0 million in aggregate principal amount of floating rate Senior Notes due 2023 (the “Floating Rate Notes”). Interest is paid quarterly in arrears on January 13, April 13, July 13, and October 13 of each year, beginning April 13, 2020. Interest will accrue from January 13, 2020 at a benchmark rate (which will initially be a three-month LIBOR rate) on the interest determination date plus 0.85%.

---

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

---

---

---

---

---

---

---

---

---

---

---

(1)

Based upon their respective appointment dates, the full-year 2019 prorated allocation percentages for Messrs. Ure, Pearl, Collins, Bourne, and Griffie are as follows: 35% for Mr. Ure, 40% for Mr. Pearl, 40% for Mr. Collins, 40% for Mr. Bourne, and 20% for Mr. Griffie. Compensation amounts shown herein for these named executive officers do not include compensation that was paid or awards that were granted by Anadarko or Occidental prior to the named executive officer’s commencement of service with us.

•	base salary;

•	annual cash incentives;

•	equity-based compensation, which, prior to the Occidental Merger, included equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan, as amended and restated (the “Omnibus Plan”), for former Anadarko employees and Occidental’s 2015 Long-Term Incentive Plan (the “Occidental LTIP Plan”) for former Occidental employees;

•	retention awards for certain of our named executive officers; however, we will not bear any costs associated with such awards; and

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

---

---

•	retirement benefits to match competitive industry practices, including participation in a savings plan, savings restoration plan, retirement plan, and retirement restoration plan;

•	severance benefits, as described below under the heading Potential Payments Upon Termination or Change of Control;

•	director 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 deferred compensation plans, and personal excess liability insurance; and

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

---

(1)	The amounts in this column reflect the base salary compensation allocated to us by Anadarko and Occidental for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect base salary compensation earned and allocated since their appointments as officers of our general partner.

(2)

The amounts in this column reflect an allocation to us of the aggregate grant date fair value of the awards, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the Omnibus Plan. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 14—Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements included under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (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 2019, see the Grants of Plan-Based Awards in 2019 table. The amounts in this column also reflect the allocation of performance unit awards, where such gross amounts were 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 Omnibus Plan. See note (2) above for valuation assumptions. The value ultimately realized upon the exercise of the stock option(s) may or may not be equal to this determined value.

(4)	The amounts in this column reflect annual cash bonus compensation expected to be allocated to us for the year ended December 31, 2019, and the amounts allocated to us for the years ended December 31, 2018 and 2017.

(5)

The amounts in this column reflect the compensation expenses related to Anadarko’s and Occidental’s retirement and savings plans that were allocated to us for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect expenses allocated since their appointments as officers of our general partner. The 2019 allocated expenses are detailed in the table below:

---

(1)

Reflects the estimated 2019 annual cash incentive payouts allocable to us. 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 Agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2019 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

(2)	Reflects, as of the time of grant, the estimated future payout allocable to us under performance units awarded in 2019. Mr. Ure is eligible to earn from 0% to 200% of the targeted award based on Occidental’s relative total shareholder return performance over a three-year performance period. The threshold value represents the minimum payment (other than zero) that was eligible to be earned.

(3)

Reflects the allocable number of shares of restricted stock and restricted stock units awarded in 2019 under the Omnibus Plan for Messrs. Griffie and Montanti and the Occidental LTIP Plan for Messrs. Ure, Collins, and Bourne, respectively. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. Mr. Ure’s award vests ratably on each February 28, 2020, 2021, and 2022. For Messrs. Collins, Bourne, and Montanti, these awards were eligible to vest ratably on each of the first three anniversaries of the grant date. Mr. Griffie’s awards will fully vest four years from the grant date.

(4)

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 at the time of grant made to named executives in 2019 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 and the Occidental LTIP Plan, see Note 14-Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein). There were no grants of stock options in 2019.

---

---

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

(2)

Generally, the restricted stock units will vest ratably over three years in installments on the first, second, and third anniversaries of the grant date. Mr. Ure’s 2017 restricted stock units will fully vest on February 28, 2020, his 2018 restricted stock units vested on February 28, 2019, and the remaining unvested portion will vest ratably on February 28, 2020 and 2021. One-third of Mr. Ure’s February 2019 restricted stock units will vest on February 28, 2020, 2021, and 2022. Messrs. Pearl’s and Griffie’s restricted stock units granted on November 10, 2016, and February 12, 2019, respectively, vest four years from the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are settled in shares of unrestricted Occidental common stock, less applicable withholding taxes. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. Pursuant to the Occidental Merger Agreement, each outstanding award of restricted stock units converted into a restricted stock and cash unit award of Occidental. Respectively, Messrs. Pearl and Griffie have the following cash portions outstanding as of December 31, 2019, that will vest ratably three years in installments on the first, second, and third anniversary of the grant date; Messrs. Pearl’s and Griffie’s award granted on November 10, 2016, and February 12, 2019, respectively, vests four years from grant date:

(3)

The number of outstanding performance units and the estimated payout percentages disclosed for each award, for Mr. Ure, are calculated based on Occidental’s relative performance ranking as of December 31, 2019, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. The three-year performance period generally starts in January in the year of grant and ends on December 31, 2020 and 2021 for 2018 and 2019 grants, respectively. Occidental’s relative performance rankings as of December 31, 2019 were 0% for the February 2018 and the February 2019 grants. For Mr. Ure’s award granted in February 2017 with a performance period beginning in 2019, the performance unit award is not outstanding as the award paid out at 0%. For Messrs. Pearl and Griffie, all outstanding performance units immediately vested on August 8, 2019, as provided under the terms of the Occidental Merger Agreement, and are not allocable to the Partnership.

---

(1)

Shares acquired and values realized on exercise include options exercised in 2019. The amounts shown in the Value Realized on Exercise column represent the difference between the market price of common stock at exercise and the applicable exercise price of such option(s). The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise. Pursuant to the Occidental Merger Agreement, for Messrs. Pearl, Griffie, and Casas and Ms. Fielder, each outstanding stock option was canceled and converted into the right to receive an amount in cash and was not allocable to the Partnership.

(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 2019 of shares of restricted stock or restricted stock units, performance units, or phantom units. For each named executive officer, the amount shown in the Value Realized on Vesting column represents the aggregate number of restricted stock units or shares of restricted stock held by such named executive officer that vested during 2019 multiplied by the common stock price on the applicable vesting date(s). For shares of restricted stock or restricted stock units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence. Mr. Ure’s shares acquired and values realized were incurred in early 2019 before becoming an executive officer of the Partnership and were never allocable to the Partnership.

---

•

A cash lump sum equal to (A) 50% of the sum of (i) the participant’s monthly base salary plus (ii) the highest annual bonus received by the participant over the previous three years, divided by twelve, multiplied by the number of years of service by the participant (clauses (i) and (ii), “Monthly Compensation”) and (B) one month of Monthly Compensation for each $10,000 of annual compensation (base salary plus highest annual bonus), rounding up to the next highest whole multiple of $10,000 if the participant’s annual compensation is not a multiple of $10,000 (the “Severance Benefit”);

•	Pro-rata annual bonus based on the participant’s target bonus percentage; and

---

•	Continuation of medical and dental insurance coverage for up to six months following termination of employment.

(1)

Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Collins and Bourne is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. The amount above for Mr. Ure reflects the single-trigger broad-based rights extended to him under the Anadarko COC Plan, as such amount is not capped under the Services Agreement. Due to the waiver of certain change of control rights discussed above, Messrs. Pearl and Griffie do not have arrangements covering involuntary not-for-cause termination other than agreements with Occidental providing for the vesting of equity or acceleration of retention payments for which, in either case, we are not obligated under the Services Agreement.

(1)

Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Pearl and Griffie is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. Although the amounts payable to Messrs. Ure, Collins, and Bourne under the Anadarko COC Plan are generally available to all WES employees, 100% of such amounts are included above because such amounts are not capped under the Services Agreement.

---

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

•	an annual retainer of $2,000 for each member of the Audit Committee, or $17,000 for the Audit Committee chair;

•	an annual retainer of $2,000 for each member of the Special Committee, or $17,000 for the Special Committee chair;

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

•	annual grants of phantom units with a value of approximately $125,000 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 Occidental).

(1)	The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2019, computed in accordance with FASB ASC Topic 718. See the table below for phantom units awarded to each non-employee director during 2019.

---

(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 2019 computed in accordance with FASB ASC Topic 718. These awards vested on August 8, 2019, as a result of Anadarko being acquired by Occidental pursuant to the Occidental Merger. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not have been equal to the value included above.

---

•	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

•	Occidental and its affiliates.

*	Less than 1%

(1)	The address for Occidental and its representatives on the Board of Directors of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

(2)	WGRI owns 161,319,520 common units, AMH owns 24,771,550 common units, WGRAH owns 38,139,260 common units, Kerr-McGee Worldwide Corporation owns 684,922 common units, and Anadarko E&P Onshore LLC owns 17,221,724 common units of WES. Occidental is the ultimate parent company of each of the foregoing entities and may, therefore, be deemed to beneficially own the units held by such entities.

(3)	Does not include unvested WES phantom unit awards as follows:

---

(1)	Based upon its Schedule 13G filed February 7, 2020, with the SEC with respect to Partnership securities held as of December 31, 2019, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 24,153,629 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 24,098,923 of the common units held by ALPS.

---

---

---

•	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.

---

---

(1)	Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.

(2)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to us by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.

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

(4)	Includes amounts related to finance leases and the APCWH Note Payable (see Note 1—Summary of Significant Accounting Policies and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

(5)	Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

(6)	Represents distributions paid to Occidental pursuant to our partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

(7)	Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

---

(1)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.

(2)

Represents distributions paid to us and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). For the year ended December 31, 2019, includes distributions to us and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

•	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.

---

---

---

---

---

---

---

---

---

---