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Western Midstream Partners, LP - Annual Report: 2021 (Form 10-K)


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021

Or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to       
WESTERN MIDSTREAM PARTNERS, LP
WESTERN MIDSTREAM OPERATING, LP
(Exact name of registrant as specified in its charter)
Commission file number:State or other jurisdiction of incorporation or organization:I.R.S. Employer Identification No.:
Western Midstream Partners, LP001-35753Delaware46-0967367
Western Midstream Operating, LP001-34046Delaware26-1075808
Address of principal executive offices:Zip Code:Registrant’s telephone number, including area code:
Western Midstream Partners, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(346)786-5000
Western Midstream Operating, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(346)786-5000
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbolName of exchange
on which registered
Western Midstream Partners, LPCommon unitsWESNew York Stock Exchange
Western Midstream Operating, LPNoneNoneNone
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Western Midstream Partners, LPYes
þ
No
¨
Western Midstream Operating, LPYes
þ
No
¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Western Midstream Partners, LPYes
¨
No
þ
Western Midstream Operating, LPYes
¨
No
þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Western Midstream Partners, LPYes
þ
No
¨
Western Midstream Operating, LPYes
þ
No
¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Western Midstream Partners, LPYes
þ
No
¨
Western Midstream Operating, LPYes
þ
No
¨


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Western Midstream Partners, LPLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
þ☐☐☐☐
Western Midstream Operating, LPLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
☐☐þ☐☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Western Midstream Partners, LP
¨
Western Midstream Operating, LP
¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Western Midstream Partners, LP
☑
Western Midstream Operating, LP
☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Western Midstream Partners, LPYes☐No
þ
Western Midstream Operating, LPYes☐
No
þ
The aggregate market value of the registrant’s common units representing limited partner interests held by non-affiliates of the registrant on June 30, 2021, based on the closing price as reported on the New York Stock Exchange.
Western Midstream Partners, LP$4.5 billion
Western Midstream Operating, LPNone
Common units outstanding as of February 17, 2022:
Western Midstream Partners, LP403,546,479
Western Midstream Operating, LPNone
DOCUMENTS INCORPORATED BY REFERENCE
None
Auditor NameAuditor LocationAuditor Firm ID
Western Midstream Partners, LPKPMG LLPHouston, Texas185
Western Midstream Operating, LPKPMG LLPHouston, Texas185
FILING FORMAT

This annual report on Form 10-K is a combined report being filed by two separate registrants: Western Midstream Partners, LP and Western Midstream Operating, LP. Western Midstream Operating, LP is a consolidated subsidiary of Western Midstream Partners, LP that has publicly traded debt, but does not have any publicly traded equity securities. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

Part II, Item 8 of this annual report includes separate financial statements (i.e., consolidated statements of operations, consolidated balance sheets, consolidated statements of equity and partners’ capital, and consolidated statements of cash flows) for Western Midstream Partners, LP and Western Midstream Operating, LP. The accompanying Notes to Consolidated Financial Statements, which are included under Part II, Item 8 of this annual report, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of this annual report, are presented on a combined basis for each registrant, with any material differences between the registrants disclosed separately.



TABLE OF CONTENTS
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COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” “WES,” “the Partnership,” or “Western Midstream Partners, LP” refer to Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) and its subsidiaries. As used in this Form 10-K, the terms and definitions below have the following meanings:
AESC: Anadarko Energy Services Company, a subsidiary of Occidental.
AMA: The Anadarko Midstream Assets, which are comprised of the Wattenberg processing plant, Wamsutter pipeline, DJ Basin oil system, DBM oil system, APC water systems, the 20% interest in Saddlehorn, the 15% interest in Panola, the 50% interest in Mi Vida, and the 50% interest in Ranch Westex.
AMH: APC Midstream Holdings, LLC.
Anadarko: Anadarko Petroleum Corporation and its subsidiaries, excluding our general partner, which became a wholly owned subsidiary of Occidental upon closing of the Occidental Merger on August 8, 2019.
Anadarko note receivable: The 30-year $260.0 million note established in May 2008 between WES Operating as the lender and Anadarko as the borrower. Following the Occidental Merger, Occidental became the ultimate counterparty. On September 11, 2020, the Partnership and Occidental entered into a Unit Redemption Agreement, pursuant to which WES Operating transferred the note receivable to Anadarko, which Anadarko immediately canceled and retired upon receipt (see Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bbls/d: Barrels per day.
Board: The board of directors of WES’s general partner.
Cactus II: Cactus II Pipeline LLC.
Chipeta: Chipeta Processing, LLC.
Chipeta LLC agreement: Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009.
Condensate: A natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions.
COSF: Centralized oil stabilization facility.
Cryogenic: The process by which liquefied gases are used to bring natural-gas volumes to very low temperatures (below approximately -238 degrees Fahrenheit) to separate natural-gas liquids from natural gas. Through cryogenic processing, more natural-gas liquids are extracted as compared to traditional refrigeration methods.
DBM: Delaware Basin Midstream, LLC.
DBM water systems: DBM’s produced-water gathering and disposal systems in West Texas.

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December 2019 Agreements: Certain agreements entered into on December 31, 2019, including (i) agreements between the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, and Occidental and/or certain of its subsidiaries, including Anadarko, and (ii) amendments to WES Operating’s debt agreements. For a description of the December 2019 Agreements, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Delivery point: The point where hydrocarbons are delivered by a processor or transporter to a producer, shipper, or purchaser, typically the inlet at the interconnection between the gathering or processing system and the facilities of a third-party processor or transporter.
DJ Basin complex: The Platte Valley system, Wattenberg system, Lancaster plant, Latham plant, and Wattenberg processing plant.
Drip condensate: Heavier hydrocarbon liquids that fall out of the natural-gas stream and are recovered in the gathering system without processing.
EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see Key Performance Metrics under Part II, Item 7 of this Form 10-K.
End-use markets: The ultimate users/consumers of transported energy products.
Equity-investment throughput: Our share of average throughput from investments accounted for under the equity method of accounting.
Exchange Act: The Securities Exchange Act of 1934, as amended.
Exchange Agreement: That certain Exchange Agreement, dated December 31, 2019, by and among WGRI, the general partner, and WES, pursuant to which (i) WGRI exchanged WES common units for the issuance of a 2.0% general partner interest in WES to the general partner and (ii) WES canceled the non-economic general partner interest in WES.
Fixed-Rate Senior Notes: WES Operating’s fixed-rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050, issued in January 2020.
Floating-Rate Senior Notes: WES Operating’s floating-rate Senior Notes due 2023.
FERC: The Federal Energy Regulatory Commission.
Fort Union: Fort Union Gas Gathering, LLC.
Fractionation: The process of applying various levels of high pressure and low temperature to separate a stream of natural-gas liquids into ethane, propane, normal butane, isobutane, and natural gasoline for end-use sale.
FRP: Front Range Pipeline LLC.
GAAP: Generally accepted accounting principles in the United States.
General partner: Western Midstream Holdings, LLC, the general partner of the Partnership.
Gpm: Gallons per minute, when used in the context of amine-treating capacity.
Hydraulic fracturing: The high-pressure injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.
Imbalance: Imbalances result from (i) differences between gas and NGLs volumes nominated by customers and gas and NGLs volumes received from those customers and (ii) differences between gas and NGLs volumes received from customers and gas and NGLs volumes delivered to those customers.

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IPO: Initial public offering.
Joule-Thompson (JT): A type of processing plant that uses the Joule-Thompson effect to cool natural gas by expanding the gas from a higher pressure to a lower pressure, which reduces the temperature.
LIBOR: London Interbank Offered Rate.
Marcellus Interest: The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania.
MBbls/d: Thousand barrels per day.
Mcf: Thousand cubic feet.
Merger: The merger of Clarity Merger Sub, LLC, a wholly owned subsidiary of the Partnership, with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of the Partnership, which closed on February 28, 2019.
Merger Agreement: The Contribution Agreement and Agreement and Plan of Merger, dated November 7, 2018, by and among the Partnership, WES Operating, Anadarko, and certain of their affiliates, pursuant to which the parties thereto agreed to effect the Merger and certain other transactions.
MGR: Mountain Gas Resources, LLC.
MGR assets: The Red Desert complex and the Granger straddle plant.
MIGC: MIGC, LLC.
Mi Vida: Mi Vida JV LLC.
MLP: Master limited partnership.
MMcf: Million cubic feet.
MMcf/d: Million cubic feet per day.
Mont Belvieu JV: Enterprise EF78 LLC.
Natural-gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane, and natural gasolines that, when removed from natural gas, become liquid under various levels of pressure and temperature.
NYSE: New York Stock Exchange.
NYMEX: New York Mercantile Exchange.
Occidental: Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner.
Occidental Merger: Occidental’s acquisition by merger of Anadarko pursuant to the Occidental Merger Agreement, which closed on August 8, 2019.
Occidental Merger Agreement: Agreement and Plan of Merger, dated as of May 9, 2019, by and among Occidental, Baseball Merger Sub 1, Inc., and Anadarko.
OTTCO: Overland Trail Transmission, LLC.
Panola: Panola Pipeline Company, LLC.

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Play: A group of gas or oil fields that contain known or potential commercial amounts of petroleum and/or natural gas.
Produced water: Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
Purchase Program: In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.
Ranch Westex: Ranch Westex JV LLC.
Receipt point: The point where hydrocarbons are received by or into a gathering system, processing facility, or transportation pipeline.
RCF: WES Operating’s $2.0 billion senior unsecured revolving credit facility that matures in February 2025.
Red Bluff Express: Red Bluff Express Pipeline, LLC.
Red Desert complex: The Patrick Draw and Red Desert processing plants, which are currently inactive, associated gathering lines, and related facilities.
Refrigeration: A method of processing natural gas by reducing the gas temperature with the use of an external refrigeration
Related parties: Occidental, the Partnership’s equity interests (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), and the Partnership and WES Operating for transactions that eliminate upon consolidation.
Rendezvous: Rendezvous Gas Services, LLC.
Residue: The natural gas remaining after the unprocessed natural-gas stream has been processed or treated.
ROTF: Regional oil treating facility.
Saddlehorn: Saddlehorn Pipeline Company, LLC.
SEC: U.S. Securities and Exchange Commission.
Services Agreement: That certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP.
Springfield system: The Springfield gas-gathering system and Springfield oil-gathering system.
Stabilization: The process to reduce the volatility of a liquid hydrocarbon stream by separating very light hydrocarbon gases, methane and ethane in particular, from heavier hydrocarbon components. This process reduces the volatility of the liquids during transportation and storage.
Tailgate: The point at which processed natural gas and/or natural-gas liquids leave a processing facility for end-use markets.
TEFR Interests: The interests in TEP, TEG, and FRP.
TEG: Texas Express Gathering LLC.
TEP: Texas Express Pipeline LLC.

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Term loan facility: WES Operating’s senior unsecured credit facility entered into in connection with the Merger, which was repaid and terminated in January 2020.
Wellhead: The point at which the hydrocarbons and water exit the ground.
WES Operating: Western Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries.
WES Operating GP: Western Midstream Operating GP, LLC, the general partner of WES Operating.
West Texas complex: The DBM complex and DBJV and Haley systems.
WGP RCF: The senior secured revolving credit facility of Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) that matured in March 2019.
WGRAH: WGR Asset Holding Company LLC.
WGRI: Western Gas Resources, Inc., a subsidiary of Occidental.
White Cliffs: White Cliffs Pipeline, LLC.
Whitethorn LLC: Whitethorn Pipeline Company LLC.
Whitethorn: A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC.

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PART I

Items 1 and 2.  Business and Properties

GENERAL OVERVIEW

WES and WES Operating. WES is a Delaware master limited partnership formed in September 2012. Our common units are publicly traded on the NYSE under the symbol “WES.” Our general partner is a wholly owned subsidiary of Occidental. WES Operating is a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop, and operate midstream assets. WES owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of WES Operating GP, which holds the entire non-economic general partner interest in WES Operating.
WES’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2021 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
We are engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts.

Available information. We electronically file our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other documents with the SEC under the Exchange Act. From time to time, we may also file registration and related statements with the SEC pertaining to equity or debt offerings.
We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing such materials with the SEC, on our website located at www.westernmidstream.com. The public may also obtain such reports from the SEC’s website at www.sec.gov.
Our Corporate Governance Guidelines, Code of Ethics and Business Conduct, Partner Code of Conduct, and the charters of the Audit Committee, the Special Committee, the ESG Committee, and the Compensation Committee of our Board are available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s secretary at our principal executive office. Our principal executive office is located at 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, TX 77380. Our telephone number is 346-786-5000.


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ASSETS AND AREAS OF OPERATION

wes-20211231_g1.jpg

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As of December 31, 2021, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities37 3 — — 
Natural-gas processing plants/trains24 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines5 — — 1 
Crude-oil pipelines3 1 — 4 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania. The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2021:
AreaAsset Type
Miles of Pipeline (1)
Compression (1) (2)
Processing or Treating Capacity (MMcf/d) (1)
Processing, Treating, or Disposal Capacity (MBbls/d) (1)
Average Throughput for Natural-Gas Assets
(MMcf/d) (3)
Average Throughput for Crude-Oil and NGLs Assets
 (MBbls/d) (3)
Average Throughput for Produced-Water Assets
(MBbls/d) (3)
Horsepower% Electric Driven
Texas / New MexicoGathering, Processing, Treating, and Disposal4,189788,54319 %1,8951,9051,737 254 717 
Transportation2,423 — — — — 244 263 — 
Rocky MountainsGathering, Processing, and Treating6,387 573,656 44 %3,100 209 2,064 90 — 
Transportation2,244 — — — — 81 65 — 
North-central PennsylvaniaGathering146 13,800 — %— — 177 — — 
Total15,389 1,375,999 29 %4,995 2,114 4,303 672 717 
_________________________________________________________________________________________
(1)All system metrics are presented on a gross basis and include owned 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.

Our operations are organized into a single operating segment that engages in gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. See Part II, Item 8 of this Form 10-K for disclosure of revenues and operating income (loss) for the years ended December 31, 2021, 2020, and 2019, and total assets for the years ended December 31, 2021 and 2020.

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ACQUISITIONS AND DIVESTITURES

Fort Union and Bison facilities. In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located in Northeast Wyoming, to a third party. During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.

STRATEGY

Our primary business objective is to create long-term value for our unitholders through continued delivery of profitable operations and return of capital to stakeholders over time. Our foundational principles of operational excellence, superior customer service, and sustainable operations influence our decision making and long-term strategy. To accomplish our primary business objective, we intend to execute the following strategy:

•Capitalizing on organic growth opportunities. We intend 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 pursue economically attractive organic business development and 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.

•Controlling our operating, capital, and administrative costs. The establishment of WES as a stand-alone midstream business has generated efficiencies between our commercial, engineering, and operations teams, and we continue to optimize and maximize the operability of our existing assets to realize cost and capital savings. We expect to continue to drive operational efficiencies and sustainable cost savings throughout the organization.

•Optimizing the return of cash to stakeholders. We intend to operate our assets and make strategic capital decisions that optimize our leverage levels consistent with investment-grade metrics in our sector while returning additional excess cash flow to stakeholders that enhances 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.

COMPETITIVE STRENGTHS

We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:

•Substantial presence in basins with historically strong producer economics. Our core operating areas are in 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 makes us a uniquely positioned, full-service midstream provider in the basin.

•Well-positioned and well-maintained assets. We believe that our large-scale 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. We believe our forward-looking facility designs enable customers to reduce their environmental impact and enhance operational efficiency.

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•Sustainability and safety. Our culture of safety and focus on protecting the environment inform decision making throughout the organization. We strive to minimize emissions by thoughtfully designing, constructing, and operating our assets, and collaborating with state and federal regulatory agencies and environmental groups, producers, and industry partners to reduce or offset emissions in our operations. Through our company-wide safety initiatives, we are committed to the safe and efficient delivery of energy for our customers, with an emphasis on true care and concern for each other, a standardized safety training program, and significant investments in asset integrity.

•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 and produced-water throughput (excluding equity investments) were serviced under fee-based contracts for the year ended December 31, 2021. In addition, we mitigate volumetric risk through minimum-volume commitments and cost-of-service contract structures. For the year ended December 31, 2021, 81% of our natural-gas throughput, 96% of our crude-oil and NGLs throughput, and 100% of our produced-water throughput were supported by either minimum-volume commitments with associated deficiency payments or cost-of-service commitments.

•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, 2021, there was $2.0 billion in available borrowing capacity under the RCF.

•Affiliation with Occidental. We continue to optimize our assets 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. 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.

We plan to effectively leverage our competitive strengths to successfully implement our business strategy. However, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objective. For a more complete description of the risks associated with our business, read Risk Factors under Part I, Item 1A of this Form 10-K.

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WES AND WES OPERATING’S RELATIONSHIP WITH OCCIDENTAL PETROLEUM CORPORATION

The officers of our general partner manage our operations and activities under the direction and supervision of the Board of our general partner, which is a wholly owned subsidiary of Occidental. Occidental is among the largest independent oil and gas exploration and production companies in the world. Occidental’s upstream oil and gas business explores for, develops, and produces crude oil and condensate, NGLs, and natural gas.
As of December 31, 2021, Occidental held (i) 200,281,578 of our common units, representing a 48.6% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.2% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGRAH, which is reflected as a noncontrolling interest within our consolidated financial statements. As of December 31, 2021, Occidental held 49.7% of our outstanding common units.
For the year ended December 31, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts.
Historically, we sold a significant amount of our natural gas and NGLs to AESC, Occidental’s marketing affiliate. In addition, we purchased natural gas from AESC pursuant to purchase agreements. While we still have some marketing arrangements with affiliates of Occidental, we began marketing and selling substantially all of our natural gas and NGLs directly to third parties beginning on January 1, 2021.
Pursuant to the Services Agreement entered into as part of the December 2019 Agreements, Occidental agreed to (i) continue to provide certain administrative and operational services to us for up to a two-year transition period, and (ii) transfer certain Occidental employees to the Partnership, with the Partnership assuming liabilities relating to those employees at the time of their transfer. In late March 2020, seconded employees’ employment was transferred to the Partnership. Most of the administrative and operational services previously provided by Occidental fully transitioned to the Partnership by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.
Although we believe our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business, it is also a source of potential conflicts. For example, Occidental is not restricted from competing with us. See Risk Factors under Part I, Item 1A and Certain Relationships and Related Transactions, and Director Independence under Part III, Item 13 of this Form 10-K for more information.


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INDUSTRY OVERVIEW

The midstream industry is the link between the exploration for and production of natural gas, NGLs, and crude oil and the delivery of these hydrocarbon components to end-use markets. Operators within this industry create value at various stages along the midstream value chain by gathering production from producers at the wellhead or production facility, separating the produced hydrocarbons into various components, delivering these components to end-use markets, and where applicable, gathering and disposing of produced water.
The following diagram illustrates the primary groups of assets found along the midstream value chain:

wes-20211231_g2.jpg
Natural-Gas Midstream Services

Midstream companies provide services with respect to natural gas that are generally classified into the categories described below.

•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.

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

Crude-Oil Midstream Services

Midstream companies provide services with respect to crude oil that are generally classified into the categories described below.

•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.

Produced-Water Midstream Services

Midstream companies provide services with respect to produced water that are generally classified into the categories described below.

•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 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.

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Contractual Arrangements

Midstream services, other than transportation, are usually provided under contractual arrangements that vary in terms of exposure to commodity-price risk. Three typical contract types, or combinations thereof, include the following:

•Fee-based. Under fee-based arrangements, the service provider typically receives a fee for each unit of (i) natural gas, NGLs, or crude oil that is 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.

See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for information regarding recognition of revenue under our contracts.

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PROPERTIES

The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, 2021.

GATHERING, PROCESSING, TREATING, AND DISPOSAL

Overview - Texas and New Mexico
LocationAssetTypeProcessing / Treating Plants
Processing / Treating Capacity (MMcf/d) (1)
Processing / Treating / Disposal Capacity (MBbls/d)
Compression Horsepower (2)
Gathering Systems
Pipeline Miles (3)
West Texas / New Mexico
West Texas complex (4)
Gathering, Processing, & Treating14 1,370 53 544,279 3 1,818 
West Texas
DBM oil system (5)
Gathering & Treating16 — 292 13,473 1 646 
West TexasDBM water systemsGathering & Disposal— — 1,300 59,390 5 804 
West Texas
Mi Vida (6)
Processing1 200 — 20,000 — — 
West Texas
Ranch Westex (7)
Processing2 125 — 10,090 — 6 
East Texas
Mont Belvieu JV (8)
Processing2 — 170 — — — 
South TexasBrasada complex Gathering, Processing, & Treating3 200 15 29,400 1 58 
South Texas
Springfield system (9)
Gathering and Treating3 — 75 111,911 2 857 
Total411,8951,905788,543124,189
_________________________________________________________________________________________
(1)Includes 70 MMcf/d of bypass capacity at the West Texas complex.
(2)Includes owned and leased compressors and compression horsepower.
(3)Includes 19 miles of transportation related to the Ramsey Residue Lines (regulated by FERC) at the West Texas complex and 15 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 2,000 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.

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West Texas and New Mexico
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West Texas gathering, processing, and treating complex

•Customers. For the year ended December 31, 2021, Occidental’s production represented 48% of the West Texas complex throughput, and the largest third-party customer provided 14% 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.

•Delivery points. 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 Energy Transfer LP’s (“ET”) 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 primarily delivered into the Sand Hills pipeline and Lone Star NGL LLC’s pipeline (“Lone Star pipeline”).

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DBM oil-gathering system, treating facilities, and storage

•Customers. As of December 31, 2021, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2021, Occidental’s production represented 97% of the total DBM oil system throughput and is subject to the Texas Railroad Commission tariff.

•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 is delivered into Plains All American Pipeline.

DBM produced-water disposal systems

•Customers. For the year ended December 31, 2021, DBM water systems throughput was from Occidental and numerous third-party producers, with Occidental’s production representing 87% of the throughput.

•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.

Mi Vida processing plant

•Customers. As of December 31, 2021, 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.

Ranch Westex processing plant

•Customers. As of December 31, 2021, 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.

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East Texas
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Mont Belvieu JV fractionation trains

•Customers. The Mont Belvieu JV does not contract with customers directly but is allocated volumes from Enterprise Products Partners LP’s (“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 Enterprise’s Seminole pipeline (“Seminole pipeline”), Skelly-Belvieu Pipeline Company, LLC’s pipeline, TEP’s pipeline, and the Panola pipeline (see Transportation within these Items 1 and 2). NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminals.

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South Texas
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Brasada gathering, stabilization, treating, and processing complex

•Customers. For the year ended December 31, 2021, Brasada complex throughput was from one third-party customer.

•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.

Springfield gathering system, stabilization facility, and storage

•Customers. For the year ended December 31, 2021, Springfield system throughput was from numerous third-party customers.

•Supply. Supply of gas and oil is sourced from third-party production in the Eagle Ford Shale Play.

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

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Overview - Rocky Mountains - Colorado and Utah
LocationAssetTypeProcessing / Treating Plants
Processing / Treating Capacity (MMcf/d) (1)
Processing / Treating Capacity (MBbls/d)Compression HorsepowerGathering Systems
Pipeline Miles (2)
Colorado
DJ Basin complex (3)
Gathering, Processing, & Treating16 1,730 54 378,644 2 2,526 
ColoradoDJ Basin oil systemGathering & Treating6 — 155 6,095 1 454 
Utah
Chipeta (4)
Processing3 790 — 76,125 — 2 
Total252,520209460,86432,982
_________________________________________________________________________________________
(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, Hambert JT (currently inactive), Wattenberg, Lancaster Trains I and II, and Latham Trains I and II processing plants, and the Wattenberg gathering system. Excludes 3,220 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.

Colorado
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DJ Basin gathering, treating, and processing complex

•Customers. For the year ended December 31, 2021, Occidental’s production represented 57% of the DJ Basin complex throughput, and the two largest third-party customers provided 28% of the throughput.

•Supply. The DJ Basin complex is supplied primarily by the Wattenberg field.

•Delivery points. As of December 31, 2021, 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”), Tallgrass Energy’s Cheyenne Connector pipeline, and Xcel Energy’s residue pipelines for natural-gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline, FRP’s pipeline, and DCP’s Wattenberg NGL pipeline for NGLs takeaway. In addition, the NGLs fractionators and associated truck-loading facility at the Platte Valley and Wattenberg plants provides access to local NGLs markets.

DJ Basin oil-gathering system, stabilization facility, and storage

•Customers. For the year ended December 31, 2021, 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.

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

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Utah
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Chipeta processing complex

•Customers. For the year ended December 31, 2021, Chipeta complex throughput was from numerous third-party customers, with the two largest customers providing 89% of the throughput.

•Supply. Chipeta’s inlet is connected to Caerus Oil and Gas LLC’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’s Mid-America Pipeline Company pipeline (“MAPL pipeline”), which provides transportation through 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 CIG pipeline, Questar pipeline, and Wyoming Interstate Company’s pipeline (“WIC pipeline”) that deliver residue gas to markets throughout the Rockies and Western United States.

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Overview - Rocky Mountains - Wyoming
LocationAssetTypeProcessing / Treating PlantsProcessing / Treating Capacity (MMcf/d)Compression HorsepowerGathering SystemsPipeline Miles
Northeast WyomingHilight systemGathering & Processing2 60 38,221 1 1,208 
Southwest Wyoming
Granger complex (1)
Gathering & Processing4 520 46,157 1 788 
Southwest WyomingRed Desert complexGathering— — 20,929 1 1,123 
Southwest Wyoming
Rendezvous (2)
Gathering— — 7,485 1 286 
Total6580112,79243,405
_________________________________________________________________________________________
(1)The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant that is currently inactive.
(2)We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.

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Northeast Wyoming

Hilight gathering system and processing plant

•Customers. For the year ended December 31, 2021, gas gathered and processed at the Hilight system was from third-party customers, with the two largest customers providing 59% of the system throughput.

•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.

Southwest Wyoming

Granger gathering and processing complex

•Customers. For the year ended December 31, 2021, Granger complex throughput was from third-party customers, with the three largest customers providing 81% of the throughput.

•Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields.

•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.
The NGLs have market access to the MAPL pipeline, which terminates at Mont Belvieu, Texas, and other local markets.

Red Desert complex

•Customers. For the year ended December 31, 2021, Red Desert complex throughput was from third-party customers, with the three largest customers providing 57% of the throughput.

•Supply and delivery points. The Red Desert complex gathers and compresses natural gas produced from the eastern portion of the Greater Green River Basin and delivers to a third party for processing.

Rendezvous gathering system

•Customers. For the year ended December 31, 2021, 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.

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Overview - North-central Pennsylvania
LocationAssetTypeCompression HorsepowerGathering SystemsPipeline Miles
North-central Pennsylvania
Marcellus (1)
Gathering13,800 3 146 
_________________________________________________________________________________________
(1)We own a 33.75% interest in the Marcellus Interest gathering systems.

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Marcellus gathering systems

•Customers. As of December 31, 2021, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided approximately 80% of the throughput for the year ended December 31, 2021. Capacity not used by priority shippers is available to other third parties as determined by the operating partner, Alta Resources Development, LLC.

•Supply and delivery points. The Marcellus Interest gathering systems have access to Transcontinental Gas Pipe Line Company, LLC’s pipeline.
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TRANSPORTATION
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LocationAssetTypeOwnership InterestPipeline Miles
Colorado, Kansas, Oklahoma
White Cliffs (1) (2)
Oil & NGLs10.00 %1,052 
Wyoming, Colorado, Kansas, Oklahoma
Saddlehorn (1) (2)
Oil20.00 %604 
Utah
GNB NGL (1)
NGLs100.00 %33 
Northeast Wyoming
MIGC (1)
Gas100.00 %243 
Southwest WyomingOTTCOGas100.00 %233 
Southwest WyomingWamsutterOil100.00 %79 
Colorado, Oklahoma, Texas
FRP (1) (2)
NGLs33.33 %447 
Texas
TEG (2)
NGLs20.00 %138 
Texas
TEP (1) (2)
NGLs20.00 %594 
Texas
Whitethorn LLC (2)
Oil20.00 %418 
Texas
Panola (1) (2)
NGLs15.00 %249 
Texas
Cactus II (1) (2)
Oil15.00 %454 
Texas
Red Bluff Express (1) (2)
Gas30.00 %123 
Total4,667 
_________________________________________________________________________________________
(1)Regulated by FERC.
(2)Operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline

•Customers. The White Cliffs pipeline had multiple committed shippers, including Occidental, as of December 31, 2021. 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 from Platteville, Colorado, to Cushing, Oklahoma.

•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, which ultimately delivers to Gulf Coast and mid-continent refineries.

Saddlehorn pipeline

•Customers. The Saddlehorn pipeline had multiple committed shippers, including Occidental, as of December 31, 2021. 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.

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Rocky Mountains - Utah

GNB NGL pipeline

•Customers. There were three primary shippers on the GNB NGL pipeline as of December 31, 2021. The GNB NGL pipeline provides capacity at the posted FERC-based rates.

•Supply. The GNB NGL pipeline has the ability to receive 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’s pipeline, and ultimately to NGLs fractionation and storage facilities in Mont Belvieu, Texas.

Rocky Mountains - Wyoming

MIGC transportation system

•Customers. For the year ended December 31, 2021, throughput on the MIGC system was from numerous third-party customers, with the two largest customers providing 81% of the system throughput. 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, and from WBI Energy Transmission, Inc.

•Delivery points. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to interstate pipelines including the CIG pipeline, Tallgrass Interstate Gas Transmission pipeline, and WIC pipeline. Volumes can also be delivered to Cheyenne Light Fuel & Power and several industrial users.

OTTCO transportation system

•Customers. For the year ended December 31, 2021, throughput on the OTTCO transportation system was from numerous 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 25 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.

Wamsutter pipeline

•Customers. For the year ended December 31, 2021, 96% of the Wamsutter pipeline throughput was from one third-party shipper. 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 active receipt points in Sweetwater County, Wyoming, and delivers crude oil to MPLX LP’s SLC Core Pipeline System.


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Texas

TEFR Interests

•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 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, 2021, FRP had multiple committed shippers, including Occidental. FRP provides capacity to other shippers at the posted FERC tariff rate.

•Texas Express Gathering. TEG consists of two NGLs gathering systems that provide plants in North Texas and the Texas panhandle with access to NGLs takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2021.

•Texas Express Pipeline. TEP delivers to NGLs fractionation and storage facilities in Mont Belvieu, Texas. TEP is supplied with NGLs from other pipelines or systems including FRP, the MAPL pipeline, and TEG. As of December 31, 2021, TEP had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates.

Whitethorn

Supply and delivery points. Whitethorn is supplied by production from the Permian Basin. Whitethorn transports crude oil and condensate from Enterprise’s Midland terminal to Enterprise’s Sealy terminal. From Sealy, shippers have access to Enterprise’s Rancho II pipeline, which extends to Enterprise’s ECHO terminal located in Houston, Texas. From ECHO, shippers have access to refineries in Houston, Texas City, Beaumont, and Port Arthur, Texas, and Enterprise’s crude-oil export facilities.

Panola pipeline

Supply and delivery points. The Panola pipeline transports NGLs from Panola County, Texas, to Mont Belvieu, Texas. As of December 31, 2021, the Panola pipeline had multiple committed shippers. The Panola pipeline provides capacity to other shippers at the posted FERC-based rates.

Cactus II pipeline

•Customers. As of December 31, 2021, 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.


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Red Bluff Express pipeline

•Customers. As of December 31, 2021, 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. In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline.
    
•Supply and delivery points. The Red Bluff Express pipeline is supplied by production from our West Texas complex and 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.

COMPETITION

The midstream services business is extremely competitive, and our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition primarily is based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures, and fuel efficiencies. Competition levels vary in our geographic areas of operation and is greatest in areas experiencing heightened producer activity and during periods of high commodity prices. Notwithstanding, Occidental and third-party producers provide certain dedications and/or minimum-volume commitments in our significant areas of operation. We believe that our assets located outside of dedicated areas, whether in or out of the aforementioned significant areas of operation, are geographically well-positioned to retain and attract both Occidental and third-party volumes.
We believe the primary advantages of our assets include proximity to established and/or future production and the available service flexibility provided to producers. We believe we can efficiently, and at competitive and flexible contract terms, provide services that customers require to gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water.

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REGULATION OF OPERATIONS

Pipeline Safety and Maintenance
Many of the pipelines we use to gather and transport oil, natural gas, and NGLs are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency under the U.S. Department of Transportation, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”), with respect to NGLs and oil. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement, and management of natural-gas, crude-oil, NGLs, and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thicknesses, design pressures, maximum operating pressures (“MOP”), pipeline patrols and leak surveys, minimum depth requirements, emergency procedures, and other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. Past operation of our pipelines with respect to these NGPSA and HLPSA requirements has not resulted in the incurrence of material costs; however, the possibility of new or amended laws and regulations or reinterpretation of PHMSA enforcement practices or other guidance with respect thereto exists, and future compliance with the NGPSA, HLPSA, and new or amended PHMSA regulations could result in increased costs that could have a material adverse effect on our results of operations or financial position.
For example, in October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on (i) the safety of gas-transmission pipelines (i.e., the first of the three parts of the Mega Rule), (ii) the safety of hazardous liquid pipelines, and (iii) enhanced emergency-order procedures. The gas-transmission rule requires operators of gas-transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the MOP. In addition, the rule updates reporting and records-retention standards for gas-transmission pipelines. This rule took effect on July 1, 2020. In November 2021, PHMSA released another part of the Mega Rule to expand regulations on U.S. natural-gas gathering lines. This rule requires operators of all onshore gas-gathering lines to report incidents and file annual reports and imposes additional safety requirements for larger diameter (i.e., outer diameters of 8.625 inches or greater), higher operating pressure gas-gathering lines. The remaining gas-transmission issues will be addressed in the last part of the Mega Rule, titled, “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments.”
The safety of hazardous liquid pipelines rule (submitted by PHMSA in October 2019) extended leak-detection requirements to all non-gathering hazardous liquid pipelines and requires operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. This rule also took effect on July 1, 2020. Finally, the enhanced emergency-order procedures rule focuses on increased emergency-safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. This rule took effect on December 2, 2019.
New laws or regulations adopted by PHMSA, like those summarized above, may impose more stringent requirements applicable to integrity-management programs and other pipeline-safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In addition, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Historically, our intrastate pipeline-safety compliance costs have not had a material adverse effect on our operations; however, there can be no assurance that such costs will remain immaterial in the future.
See risk factor, “Federal and state legislative and regulatory initiatives relating to pipeline safety and integrity management that require the performance of ongoing assessments and implementation of preventive measures, the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation” under Part I, Item 1A of this Form 10-K for further discussion on pipeline safety standards.


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Interstate Natural-Gas Pipeline Regulation
Regulation of pipeline-transportation services may affect certain aspects of our business and the market for our products and services. The operations of our MIGC pipeline and the Ramsey Residue Lines are subject to regulation by FERC under the Natural Gas Act of 1938 (the “NGA”). Under the NGA, FERC has authority to regulate natural-gas companies that provide natural-gas pipeline-transportation services in interstate commerce. Federal regulation extends to such matters as the following:
•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.

Interstate natural-gas pipelines regulated by FERC also are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural-gas pipelines may interact with their marketing affiliates (unless FERC has granted a waiver of such standards). FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes. FERC’s market manipulation regulations make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. FERC and CFTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC and CFTC, we could be subject to substantial penalties and fines.
Interstate Liquids-Pipeline Regulation
Regulation of interstate liquids-pipeline services may affect certain aspects of our business and the market for our products and services. Our GNB NGL pipeline provides interstate service as a FERC-regulated common carrier under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. We also own interests in FRP, TEP, Saddlehorn, Panola, Cactus II, and White Cliffs, each of which provides interstate services as a FERC-regulated common carrier under the same statues and regulations. FERC regulation requires that interstate liquid-pipeline rates, including rates for transportation of NGLs and crude oil, be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory. Rates of interstate NGLs and crude-oil pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease rates in accordance with an index adjustment specified by FERC. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, FERC established the index level for the five-year period commencing on July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer-price index for finished goods (“PPI-FG”) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022, through June 30, 2026. FERC ordered pipelines with filed rates that exceed their index ceiling levels
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based on PPI-FG minus 0.21% to file rate reductions effective March 1, 2022. Subsequent appellate review could result in a further change to the index. Under FERC’s regulations, an NGLs or crude-oil pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.
The Interstate Commerce Act permits interested persons to challenge proposed new rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months pending an investigation. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. The just-and-reasonable rate used to calculate refunds cannot be lower than the last tariff rate approved as just and reasonable. FERC may also investigate, upon complaint or on its own initiative, a changed rate and may order a carrier to reduce its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for charges in excess of a just-and-reasonable rate for a period of up to two years prior to the filing of a complaint. FERC’s Revised Policy on Treatment of Income Taxes (“Revised Policy Statement”), that no longer permits MLPs to recover an income tax allowance in cost-of-service rates, applies to our pipelines regulated under the Interstate Commerce Act. The Revised Policy Statement may result in an adverse impact on revenues associated with the cost-of-service rates of our FERC-regulated interstate pipelines.
As discussed above, the CFTC holds authority to monitor certain segments of the physical and futures energy commodities market. The Federal Trade Commission (the “FTC”) has authority to monitor petroleum markets in order to prevent market manipulation. The CFTC and FTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by the CFTC and FTC, we could be subject to substantial penalties and fines.

Natural-Gas Gathering Pipeline Regulation
Regulation of gas-gathering pipeline services may affect certain aspects of our business and the market for our products and services. Natural-gas gathering facilities are exempt from the jurisdiction of FERC. We believe that our gas-gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is not subject to FERC jurisdiction, although FERC has not made any determinations with respect to the jurisdictional status of any of our gas pipelines other than MIGC and the Ramsey Residue Lines. However, the distinction between FERC-regulated gas-transmission services and federally unregulated gathering services has been the subject of substantial litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. FERC makes jurisdictional determinations on a case-by-case basis. Our natural-gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural-gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Our natural-gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural-gas gathering activities, which allows natural-gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil, and criminal remedies. To date, there has been no adverse effect to our systems resulting from these regulations.
FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent
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such transactions do not have a “nexus” to jurisdictional transactions. In addition, FERC’s market oversight and transparency regulations also may apply to otherwise non-jurisdictional entities to the extent annual purchases and sales of natural gas reach a certain threshold. FERC’s civil penalty authority, described above, would apply to violations of these rules.
Intrastate-Pipeline Regulation
Regulation of intrastate pipeline services may affect certain aspects of our business and the market for our products and services. Intrastate natural-gas and liquids transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural-gas transportation and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates and services varies from state to state. Regulations within a particular state generally will affect all intrastate pipeline operators within the state on a comparable basis; thus, we believe that the regulation of intrastate transportation in any state in which we operate will not disproportionately affect our operations.
We own an interest in Red Bluff Express, which offers natural-gas transportation services under Section 311 of the Natural Gas Policy Act of 1978. Such pipelines are required to meet certain quarterly reporting requirements, providing detailed transaction information that could be made public. Such pipelines also will be subject to periodic rate review by FERC. In addition, FERC’s anti-manipulation, market-oversight, and market-transparency regulations may extend to intrastate natural-gas pipelines, although they may otherwise be non-jurisdictional, and FERC’s civil penalty authority, described above, would apply to violations of these rules.
Financial-Reform Legislation
For a description of financial reform legislation that may affect our business, financial condition, and results of operations, read Risk Factors under Part I, Item 1A of this Form 10-K for more information.

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ENVIRONMENTAL MATTERS AND OCCUPATIONAL HEALTH AND SAFETY REGULATIONS

Our business operations are subject to numerous federal, regional, state, tribal, and local environmental and occupational health and safety laws and regulations. The more significant of these existing environmental laws and regulations include the following legal standards that exist currently in the United States, as amended from time to time:
•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;
•the Occupational Safety and Health Act, 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, potentially 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 hazardous materials, pipeline safety, and emergency response preparedness.


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Additionally, regional, state, tribal, and local jurisdictions exist in the United States where we operate that also have, or are developing or considering developing, similar environmental laws and regulations governing many of these same types of activities. While the legal requirements imposed under state law may be similar in form to federal laws and regulations, in some cases, the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development, or expansion of a project or substantially increase the cost of doing business. These federal and state environmental laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts and oil and natural-gas development in close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas, are expected to continue to have a considerable impact on our operations.
In connection with our operations, we have acquired certain properties supportive of oil and natural-gas activities from third parties whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances, or wastes were not under our control. Under environmental laws and regulations, we could incur strict joint and several liability for remediating hydrocarbons, hazardous substances, or wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or recycling, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.
These federal and state laws and their implementing regulations generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals, or other releases, to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective-action obligations or the incurrence of capital expenditures; the occurrence of delays or cancellations in the permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Moreover, there exist environmental laws that provide for citizen suits, which allow individuals and environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. See the following Risk Factors under Part I, Item 1A of this Form 10-K for further discussion on environmental matters such as ozone standards, climate change, including methane or other GHG emissions, hydraulic fracturing, and other regulatory initiatives related to environmental protection: “We are subject to stringent and comprehensive environmental laws and regulations that may expose us to significant costs and liabilities,” “Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, and transporting services we provide,” “Changes in laws or regulations regarding hydraulic fracturing could result in increased costs, operating restrictions, or delays in the completion of oil and natural-gas wells, which could decrease the need for our gathering and processing services,” and “Adoption of new or more stringent legal standards relating to induced seismic activity associated with produced-water disposal could affect our operations.” The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable, as existing standards are subject to change and new standards continue to evolve.
We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not have a material adverse effect on our business, financial condition, results of operations, or cash flows in the future, or that new or more stringently applied existing laws and regulations will not materially increase our costs of doing business. Although we are not fully insured against all environmental risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, and claims for damages to property or persons or imposition of penalties resulting from our operations, could have a material adverse effect on our results of operations.
The following are examples of proposed and/or final regulations or other regulatory initiatives that could have a potentially material impact on us:

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•Ground-Level Ozone Standards. In 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion under the primary standard to 70 parts per billion under the secondary standard to provide requisite protection of public health and welfare. 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. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. State implementation of the 2015 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 (“VOC”) 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 VOC 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 November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural-gas sector. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. 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, methane fees, 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, which became effective in November 2016, and to which the United States formally rejoined in February 2021. The United States has established an economy-wide target of reducing its net GHG emissions by 50%, to 52% below 2005 levels in 2030, and achieving net zero GHG-emissions economy-wide by no later than 2050. Additionally, in Colorado, the Colorado Air Quality Control Commission adopted regulations in December 2021 that increase leak detection and repair inspections at oil and natural-gas facilities and required the reduction of methane emissions from certain oil and natural-gas operations. 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 operations.


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We also dispose of produced water generated from oil and natural-gas production operations. The legal standards related to the disposal of produced water into non-producing geologic formations by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to seismic events near injection wells used for the disposal of produced water. In response to such concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or are otherwise investigating the existence of a relationship between seismicity and the use of such wells. For example, Colorado developed and follows guidance when issuing underground injection-control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells that impose certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults, and also is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal-well operations. The Texas Railroad Commission also has adopted similar permitting, operating, and reporting rules for disposal wells. Another consequence of seismic events near produced-water disposal wells is the introduction of class action lawsuits, which allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. One or more of these developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, which could have a material adverse effect on our results of operations, capital expenditures and operating costs, and financial condition.

TITLE TO PROPERTIES AND RIGHTS-OF-WAY

Our real property is classified into two categories: (i) parcels that we own in fee title and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located is held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessor. We or our affiliates have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, or license held by us or to our title to any material lease, easement, right-of-way, permit, or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses.
Some of the leases, easements, rights-of-way, permits, and licenses transferred to us by Occidental required the consent of the grantor of such rights, which in certain instances was a governmental entity. We believe we have obtained sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits, or authorizations that have not been obtained, we have determined these will not have a material adverse effect on the operation of our business should we fail to obtain such consents, permits, or authorization in a reasonable time frame.


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HUMAN CAPITAL RESOURCES

The officers of our general partner manage our operations and activities under the direction and supervision of the Board. As of December 31, 2021, WES employed 1,127 persons, all of whom reside in the United States. None of these employees are covered by collective bargaining agreements, and WES considers its employee relations to be good.
Our ability to provide exceptional customer service and generate value for our stakeholders is dependent on our success in recruiting and retaining top talent. To that end, we offer our employees competitive compensation packages and incentive-based awards, as well as a comprehensive offering of health and retirement benefits. In addition, we offer our employees a wide range of programs to help foster work-life balance and support working families, including flexible work schedules and a generous paid-time-off program. To further support our people and the communities in which we live and work, we created the Community Betterment Task Force, comprised of WES senior leadership, to lead and implement our social involvement, and volunteering efforts. Our 2021 voluntary attrition rate was 6.63%, which is consistent with our historical rates and is, we believe, in part reflective of the efforts described above that we take to recruit and retain top talent.
Through regular training and orientation for employees and contractors and the inclusion of safety metrics in our incentive compensation program, we endeavor to create a culture in which safety underpins all decision making throughout the organization. As our employees continue to provide essential services during the COVID-19 crisis, we have developed and implemented a COVID-19 mitigation plan based on the Centers for Disease Control and Prevention (“CDC”) and state health guidelines. This plan includes the implementation of employee health-screening protocols, elevated cleaning measures, reducing shared spaces, purchasing masks for all personnel to be used when social-distancing measures are not possible, and providing work-from-home support to facilitate remote working. To ensure employees take adequate care of themselves and protect their coworkers’ health, employees receive additional paid sick leave until they are cleared to return to work. Additionally, as vaccines have become available for our workforce, we have actively communicated updates, providing up-to-date information and targeted communications about vaccine eligibility in each of the states where we operate.

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Item 1A.  Risk Factors

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this Form 10-K, and may make in other public filings, press releases, and statements by management, forward-looking statements concerning our operations, economic performance, and financial condition. These forward-looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward-looking” information.
Although we and our general partner believe that the expectations reflected in our forward-looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following:

•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;

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•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;

•the resolution of litigation or other disputes;

•conflicts of interest among us, our general partner and its related parties, 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;

•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;

•the economic uncertainty from the worldwide outbreak of COVID-19;

•cyber attacks or security breaches; 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.

Risk factors and other factors noted throughout this Form 10-K could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
Common units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Form 10-K in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, or results of operations could be materially and adversely affected. In such a case, the common units’ trading price could decline, and you could lose part or all of your investment.

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RISKS INHERENT IN OUR BUSINESS

We are dependent on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose. A material reduction in Occidental’s production that is gathered, treated, processed, or transported by our assets would result in a material decline in our revenues and cash available for distribution.
We rely on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose. For the year ended December 31, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. Occidental may decrease its production in the areas serviced by us and is under no contractual obligation to maintain its production volumes dedicated to us pursuant to the terms of our applicable gathering agreements. The loss of a significant portion of production volumes supplied by Occidental would result in a material decline in our revenues and our cash available for distribution. In addition, Occidental may determine that drilling activity in areas other than our areas of operation is strategically more attractive. A shift in Occidental’s focus away from our areas of operation could result in reduced throughput on our systems and a material decline in our revenues and cash available for distribution.
Because we are dependent on Occidental as our largest customer and the owner of our general partner, any development that materially and adversely affects Occidental’s operations, financial condition, or market reputation could have a material and adverse impact on us. Material adverse changes at Occidental could restrict our access to capital, make it more expensive to access the capital markets, or increase the costs of our borrowings.
We are dependent on Occidental as our largest customer and the owner of our general partner, and we expect to derive significant revenue from Occidental for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Occidental’s production, financial condition, leverage, market reputation, liquidity, results of operations, or cash flows may adversely affect our revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Occidental, including, but not limited to, the volatility of oil and natural-gas prices, the availability of capital on favorable terms to fund Occidental’s exploration and development activities, the political and economic uncertainties associated with Occidental’s foreign operations, transportation-capacity constraints, and shareholder activism.
Further, we are subject to the risk of non-payment or non-performance by Occidental, including with respect to our gathering and transportation agreements. We cannot predict the extent to which Occidental’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Occidental’s ability to perform under our gathering and transportation agreements with Occidental. Accordingly, any material non-payment or non-performance by Occidental could reduce our ability to make distributions to our unitholders.
Any material limitations to our ability to access capital as a result of adverse changes at Occidental could limit our ability to obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Occidental could adversely impact our unit price, thereby limiting our ability to raise capital through equity issuances or debt financing, or adversely affect our ability to engage in or expand or pursue our business activities, and also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
See Occidental’s reports filed under the Securities and Exchange Act of 1934, as amended, with the SEC (which are not, and shall not be deemed to be, incorporated by reference herein), for a full discussion of the risks associated with Occidental’s business.
Occidental’s ownership of our general partner may result in conflicts of interest.
Occidental owns our general partner. Occidental’s ownership of our general partner may result in conflicts of interest. The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to Occidental. At the same time, our general partner has duties to manage us in a manner that is beneficial to our unitholders. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental. As a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders.
Our future prospects depend on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us. Additional
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conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and us. For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us.
Any future credit-rating downgrade could negatively impact our cost of and ability to access capital.
Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit rating assigned to WES Operating’s debt by the major credit rating agencies. As of February 15, 2022, WES Operating’s long-term debt was rated “BBB-” by Standard and Poor’s (“S&P”), BB+ by Fitch Ratings, and “Ba2” by Moody’s Investors Service (“Moody’s”). In 2020, WES Operating’s credit ratings were downgraded below investment grade by Fitch, S&P, and Moody’s. Because of these downgrades, financing costs under the RCF increased. Additionally, WES Operating currently has $3.1 billion of outstanding senior notes that provide for changes to the coupon rates following changes to WES Operating’s credit rating.
Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt in the public debt markets and negatively impact our cost of capital, future interest costs, and ability to effectively execute aspects of our business strategy. Future credit-rating downgrades also could trigger obligations to provide financial assurance of our performance under certain contractual arrangements. We may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements, such as pipeline transportation contracts and NGLs and gas-sales contracts. At December 31, 2021, there were $5.1 million in letters of credit or cash-provided assurance of our performance under contractual arrangements with credit-risk-related contingent features.
Sustained low natural-gas, NGLs, or oil prices could adversely affect our business.
Sustained low natural-gas, NGLs, or oil prices impact natural-gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over the medium to long term, resulting in reduced throughput on our systems. Such declines also potentially affect the ability of our vendors, suppliers, and customers to continue operations. As a result, sustained lower natural-gas and crude-oil prices could have a material adverse effect on our business, results of operations, financial condition, and our ability to pay cash distributions to our unitholders.
In general terms, the prices of natural gas, oil, condensate, NGLs, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control. For example, market prices for natural gas have declined substantially from the highs achieved in 2008 and have generally remained depressed for several years. More recently, the COVID-19 pandemic and resulting mitigation measures have had an adverse impact on global economic conditions, and have contributed to significant volatility in demand for oil, NGLs, and natural gas, resulting in extended periods of lower commodity prices that negatively impacted our and our customers’ financial outlooks and activity levels.
Because of the natural decline in production from existing wells, our success depends on our ability to compete for new sources of oil and natural-gas throughput, which is dependent on certain factors beyond our control. Any decrease in the volumes that we gather, process, treat, and transport could affect our business and operating results adversely.
The volumes that support our business are dependent on, among other things, the level of production from natural-gas and oil wells connected to our gathering systems and processing and treating facilities. This production will naturally decline over time. As a result, our cash flows associated with production from these wells also will decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of oil and natural-gas throughput. The primary factors affecting our ability to obtain sources of oil and natural-gas throughput include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells to the extent such wells are not dedicated to our systems, and (iii) our ability to capture volumes currently gathered or processed by third parties. Our industry is highly competitive, and we compete with similar companies in our areas of operation. In addition, our customers, including Occidental, may develop their own midstream systems in lieu of using ours.
While Occidental and other third-party producers have dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production declines. We also have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected commodity prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs, and other production and development costs. Sustained
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reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets.
Because of these factors, producers (including Occidental) may be deterred from developing known oil and natural-gas reserves existing in areas served by our assets. Moreover, Occidental and other third-party producers may not develop the acreage it has dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
The global outbreak of COVID-19 may have an adverse impact on our operations and financial results.
The global outbreak of COVID-19 poses significant risks to our business and to the markets in which we operate. Many of our facilities require our field personnel to be on location to ensure safe and efficient operations. If a significant percentage of our workforce is unable to work, due to illness or travel or other COVID-19-related restrictions, we may experience significant operational disruptions or inefficiencies and a heightened risk of safety and environmental incidents. Similarly, we may be impacted by workforce attrition to the extent our employees are resistant to any vaccine or testing mandates that may be imposed upon us. Any such developments could materially and adversely affect our earnings, cash flows, and ability to make cash distributions to our unitholders.
Additionally, many of our employees have been and may in the future be subject to pandemic-related work-from-home requirements, which stress the capabilities of our information technology systems, including those relating to system security; disrupt normal channels of intracompany communications and key business processes; and heighten the risk of cyber-security threats and operational, health, or safety-related incidents at our facilities. For these reasons, limited working arrangements and other related restrictions may impact our operations and management effectiveness and may introduce, or increase the likelihood of, material risks to our business, operations, productivity, and results of operations.
Our profitability may be negatively impacted by inflation in the cost of labor, materials, and services.
Although inflation in the United States has been relatively low in recent years, the U.S. economy could experience a significant inflationary effect from, among other things, supply chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis. While we cannot predict any future trends in the rate of inflation, the global COVID-19 pandemic has brought unprecedented uncertainty to the near-term economic outlook. A significant increase in inflation would raise our costs for labor, materials, and services, and to the extent we are unable to recover higher costs through our commercial agreements, would negatively impact our profitability and cash flows available for distribution to unitholders.
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows rather than on our profitability, and we may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay distributions at previously announced levels to holders of our common units, or at all, even during periods in which we record net income.
The amount of cash we have available for distribution primarily depends on our cash flows and not solely on profitability as determined by GAAP, which will be affected by non-cash items. As a result, we may make cash distributions for periods in which we record losses for financial accounting purposes and may not make cash distributions for periods in which we record net earnings for financial accounting purposes.
To pay the announced fourth-quarter 2021 distribution of $0.32700 per unit per quarter, or $1.30800 per unit per year, we require per-quarter available cash of $134.7 million, or $538.8 million per year, based on the number of common units outstanding at January 31, 2022. We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at currently announced levels. The amount of cash we can distribute on our units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter.
We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders.
On some of our systems, we rely on third-party customers for substantially all of our revenues related to those assets. The loss of a portion or all of these customers’ contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions, replacements of contracts, or otherwise, could reduce our ability to make cash distributions to our unitholders. Further, to the extent any of our third-party customers is in financial distress or enters bankruptcy proceedings, the related customer contracts may be renegotiated at lower rates or altogether rejected.
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Since the beginning of 2020, we have been engaged in initiatives that will facilitate our ability to operate more independently from Occidental. Our separation from Occidental entails risks and uncertainties that may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
The difficulties of creating a stand-alone structure include, among other things, implementing operational and administrative technology systems, maintaining effective internal controls, replicating a regulatory compliance infrastructure, and hiring, training and retaining qualified personnel, the loss of which could reduce our competitiveness and prospects for future success. While we have achieved significant milestones in our separation from Occidental, attention to such organizational activities is continuing and could divert management’s attention from our existing business. Additionally, newly adopted systems, controls, and compliance infrastructure may face post-implementation challenges in the near term.
If any of these risks, or other unanticipated liabilities or costs were to arise, then desired benefits from our efforts to become independent from Occidental may not materialize. Such difficulties may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
Implementation of Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state.
On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado. The new legislation reforms oversight of oil and natural-gas exploration and production activities in the state. The mission of the Colorado Oil and Gas Conservation Commission (“COGCC”) has changed from fostering energy development in the state to regulating the industry in a manner that is protective of public health and safety and the environment. The new legislation also authorizes Colorado cities and counties to assume an increased role in regulating oil and natural-gas operations within their jurisdictions in a manner that may be more stringent than state-level rules. Effective January 15, 2021, COGCC began implementing the new Senate Bill 19-181 rules that include a unified permitting process, increased setbacks from schools, limitations on venting and flaring, enhanced wildlife protections, and, in conjunction with the Colorado Department of Public Health and Environment, requirements to evaluate the cumulative impacts of oil and gas operations. COGCC will finalize a rule proposing increased financial assurance later this year and additional rulemakings may be expected. Operators are adjusting to the new requirements, but are experiencing delayed drilling permit issuance and potentially will face increased operating costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.
Changes in laws or regulations regarding hydraulic fracturing could result in increased costs, operating restrictions, or delays in the completion of oil and natural-gas wells, which could decrease the need for our gathering and processing services.
While we do not conduct hydraulic fracturing, our oil and natural-gas exploration and production customers do conduct such activities. Hydraulic fracturing is an essential and common practice used by many of our customers to stimulate production of natural gas and oil from dense subsurface rock formations such as shales. Hydraulic fracturing is typically regulated by state oil and natural-gas commissions, but several federal agencies, including the EPA and the BLM, also have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the hydraulic-fracturing process.
At the state level, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent disclosure, permitting, or well-construction requirements on hydraulic-fracturing operations, and states could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic-fracturing activities in particular. If new or more-stringent federal, state, or local legal restrictions, prohibitions or regulations, or ballot initiatives relating to the hydraulic-fracturing process are adopted in areas where our oil and natural-gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for our gathering and processing services. Moreover, increased regulation of the hydraulic-fracturing process also could lead to greater opposition to, and litigation over, oil and natural-gas production activities using hydraulic-fracturing techniques. Any one or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.
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Adoption of new or more stringent legal standards relating to induced seismic activity associated with produced-water disposal could affect our operations.
We dispose of produced water generated from oil and natural-gas production operations. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to recent seismic events near injection wells used for the disposal of produced water. In response to such concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or are otherwise investigating the existence of a relationship between seismicity and the use of such wells. These developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations.
Adverse developments in our geographic areas of operation could disproportionately impact our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.
Our business and operations are concentrated in a limited number of producing areas. Due to our limited geographic diversification, adverse operational developments, regulatory or legislative changes, or other events in an area in which we have significant operations could have a greater impact on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders than if our operations were more diversified.
Our indebtedness may limit our ability to capitalize on acquisitions and other business opportunities or our flexibility to obtain financing.
The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”) or the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments. See Part II, Item 7 of this Form 10-K for a further discussion of the terms of the RCF and Notes.
Furthermore, our indebtedness and related debt-service costs could impair our ability to obtain additional financing, reduce funds available for operations and business opportunities, make us more vulnerable to competitive pressures or market downturns, and limit our financial and operational flexibility.
Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service indebtedness in the future, we will be forced to take actions such as reducing distributions; reducing or delaying our business activities, acquisitions, investments, or capital expenditures; selling assets; or seeking additional equity capital. We may not be able to execute any of these actions on satisfactory terms or at all.
We may not be able to obtain funding on acceptable terms or at all. This may hinder or prevent us from meeting our future capital needs.
Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry. The repricing of credit risk and the recent relatively weak industry conditions have made, and will likely continue to make, it difficult for some entities to obtain funding. In addition, as a result of concerns about the stability and solvency of some of our counterparties, the cost of obtaining financing from the credit markets generally has increased as many lenders and institutional investors have increased required rates of return, enacted tighter lending standards, refused to provide funding on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers. Further, we may be unable to obtain adequate funding under the RCF if our lending counterparties become unable to meet their funding obligations. Due to these factors, we cannot be certain that funding will be available if needed and to the extent required on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, results of operations, cash flows, and ability to make cash distributions to our unitholders.
Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results.
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Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. A material weakness is a deficiency, or a combination of deficiencies, in our internal controls that result in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal control is necessary for us to provide reliable financial reports and deter and detect any material fraud. If we cannot provide reliable financial reports or prevent material fraud, our reputation and operating results will be harmed. Our efforts to develop and maintain our system of internal controls and to remediate material weaknesses in our controls may not be successful, and we may be unable to maintain adequate control over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls, could harm our operating results. Ineffective internal control also could cause investors to lose confidence in our reported financial information.
Our business could be negatively affected by security threats, including cyber-threats, and other disruptions.
We face various security threats, including cyber-threats to the security of our facilities and infrastructure, attempts to gain unauthorized access to sensitive information or to render data or systems unusable, and terrorist acts. Additionally, destructive forms of protests by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural-gas-related activities could potentially result in damage or injury to persons, property, or the environment, or lead to extended interruptions of our or our customers’ operations. Our implementation of procedures and controls to monitor and mitigate security threats and to increase security for our facilities, infrastructure, and information may result in increased costs. There can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring.
Cyber-attacks, in particular, are becoming more sophisticated and include malicious software intended to gain unauthorized access to data and systems, electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. For example, the gathering, processing, treating, and transportation of natural gas from our gathering systems, processing facilities, and pipelines are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities. Disruption of those communications, whether caused by cyber-attacks or otherwise, may disrupt our ability to deliver natural gas and control these assets.
There is no assurance that we will not suffer material losses from future cyber-attacks, and as such threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cyber vulnerabilities. Any terrorist or cyber-attack against, or other disruption of, our assets or computer systems could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems. Therefore, in the future, throughput on our systems could be less than we anticipate.
We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is greater than we anticipate, and we are unable to secure additional sources of oil and natural gas, there could be a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
Our results of operations could be adversely affected by asset impairments.
If commodity prices decrease, and producer activity reduces accordingly, we may be required to write down the value of our midstream properties if the estimated future cash flows from these properties fall below their respective net book values. Because we are a related party of Occidental, the assets we previously acquired from Anadarko were recorded at Anadarko’s carrying value prior to the transaction. Accordingly, we may be at an increased risk for impairments because the initial book values of a substantial portion of our assets do not have a direct relationship with, and in some cases could be significantly higher than, the consideration paid to acquire such assets. See the discussion of material impairments in Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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If third-party pipelines or other facilities interconnected to our gathering, transportation, treating, or processing systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
Our gathering, transportation, treating, and processing systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat, store, or process crude oil, natural gas, or NGLs, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected. For example, during the market disruptions caused by the outbreak of COVID-19, there were concerns that domestic oil-storage capacity could reach operational limits. If such an event had occurred, our customers might have shut-in field production due to limited downstream-takeaway alternatives or resulting wellhead economics. If production is shut-in for these or for other reasons, affected producers may become insolvent or seek to avoid their contractual obligations with us, in which case, our earnings, cash flows from operations, and ability to make cash distributions to our unitholders could be materially and adversely impacted.
A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
We believe that our gas-gathering systems meet the traditional tests FERC has used to determine if a pipeline is a gas-gathering pipeline and is, therefore, not subject to FERC jurisdiction. FERC, however, has not made any determinations with respect to the jurisdictional status of any of these gas-gathering systems. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of ongoing litigation and, over time, FERC policy concerning which activities it regulates and which activities are excluded from its regulation has changed. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has regulated the gas-gathering activities of interstate pipeline transmission companies more lightly, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural-gas gathering may begin to receive greater regulatory scrutiny at the state and federal levels.
FERC makes jurisdictional determinations for natural-gas gathering and liquids lines on a case-by-case basis. The classification and regulation of our pipelines are subject to change based on future determinations by FERC, the courts, or Congress. A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase. For additional information, read Regulation of Operations–Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.
Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, and transporting services we provide.
The threat of climate change continues to attract considerable attention in the United States and foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs, as well as to restrict or eliminate such future emissions. Further, new legislation, policies, or regulations may inhibit development plans of our producer customers, which could result in lower volumes transported across our assets. Changes to climate-change or other air-emissions laws and regulations, or reinterpretations of enforcement or other guidance with respect thereto, that govern the areas in which we operate may impact our operations negatively by increasing our compliance costs and the compliance costs of our customers. In addition, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. A material reduction in capital available to the energy industry could make it more difficult to secure funding for exploration, development, production, and transportation activities, which could result in decreased demand for our services, or difficulty in securing capital for new construction projects. For additional information read, “Environmental Matters” under Items 1 and 2 of this Form 10-K.
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Federal and state legislative and regulatory initiatives relating to pipeline safety and integrity management that require the performance of ongoing assessments and implementation of preventive measures, the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation.
Legislation adopted in recent years has resulted in more-stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline-safety requirements on pipeline operators. For instance, pursuant to its authority under federal law, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs, which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require the operators of covered pipelines to, among other things, perform ongoing assessments of pipeline integrity and implement preventive and mitigating actions. The imposition of new pipeline safety or integrity management requirements pursuant to existing federal laws or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which could result in our incurring increased capital expenditures and operating costs that could have a material adverse effect on our results of operations or financial position. For additional information regarding PHMSA regulations, read Regulation of Operations—Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.
Additionally, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Moreover, PHMSA and one or more state regulators, including the Texas Railroad Commission, have expanded the scope of their regulatory inspections in recent years to include certain in-plant equipment and pipelines found within NGLs fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGLs fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA and EPA requirements, where such changes or modifications may result in additional capital costs, possible operational delays, and increased costs of operation that, in some instances, may be significant.
Some portions of our pipeline systems have been in service for several decades, and we have a limited ownership history with respect to certain of our assets. There could be unknown events or conditions, or increased maintenance or repair expenses, and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Some portions of the pipeline systems that we operate were in service for many decades, prior to our purchase of these systems. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems also could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations.
We are subject to stringent and comprehensive environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and comprehensive federal, tribal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These environmental laws and regulations may impose numerous obligations that are applicable to our operations, including: (i) the acquisition of permits to conduct regulated activities; (ii) restrictions on the types, quantities, and concentrations of materials that can be released into the environment; (iii) limitations on the generation, management, and disposal of wastes; (iv) limitations or prohibitions of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions, and other protected areas; (v) requiring capital expenditures to limit or prevent releases of materials from our pipelines and facilities; and (vi)
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imposition of substantial restoration and remedial liabilities and obligations with respect to abandonment of facilities and for pollution resulting from our operations or existing at our owned or operated facilities. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly remedial or corrective actions. Failure to comply with these laws, regulations, and permits or any newly adopted legal requirements may result in the assessment of sanctions, including administrative, civil, and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the incurrence of capital expenditures, the occurrence of delays or cancellations in the permitting, development or expansion of projects, and the issuance of injunctions limiting or preventing some or all of our operations in particular areas.
We may incur significant environmental costs and liabilities in connection with our operations due to our handling of natural gas, crude oil, NGLs, and other petroleum products, because of pollutants from our operations emitted into ambient air or discharged or released into surface water or groundwater, and as a result of historical industry operations and waste-disposal practices. For example, an accidental release as a result of our operations could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by owners of the properties through which our gathering or transportation systems pass, neighboring landowners, and other third parties for personal injury, natural-resource and property damages, and fines or penalties for related violations of environmental laws or regulations. Joint and several strict liabilities may be incurred, without regard to fault, under certain of these environmental laws and regulations. In addition, stricter laws, regulations, or enforcement policies could increase our operational or compliance costs and the costs of any restoration or remedial actions that may become necessary, which could have a material adverse effect on our results of operations or financial condition. The adoption of any laws, regulations, or other legally enforceable mandates could increase our oil and natural-gas exploration and production customers’ operating and compliance costs and reduce the rate of production of oil or natural gas by operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.
Our construction of new assets is subject to regulatory, environmental, political, legal, and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects. Delays in the completion of new downstream assets, or the unavailability of existing downstream assets, due to environmental, regulatory, or political considerations, could have an adverse impact on the completion or utilization of our growth projects. In addition, construction activities could be subject to state, county, and local ordinances that restrict the time, place, or manner in which those activities may be conducted. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize.
We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.
In recent years, certain institutional investors, including public pension funds, have placed increased importance on the implications and social cost of environmental, social, and governance (“ESG”) matters. ESG initiatives generally seek to divert investment capital from companies involved in certain industries or with disfavored governance structures. The energy industry as a whole has received the attention of such activists, as have companies with our partnership governance model.
Investors’ increased focus and activism related to ESG and similar matters may constrain our ability to raise capital. Any material limitations on our ability to access capital as a result of such scrutiny could limit our ability to obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future. Similarly, such activism could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our or its business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

We have partial ownership interests in several joint-venture legal entities that we do not operate or control. As a result, among other things, we may be unable to control the amount of cash we receive or retain from the operation of these entities, and we could be required to contribute significant cash to fund our share of joint-venture operations, which could affect our ability to distribute cash to our unitholders adversely.
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Our inability, or limited ability, to control the operations and/or management of joint-venture legal entities in which we have a partial ownership interest may result in our receiving or retaining less cash than we expect. We also may be unable, or limited in our ability, to cause any such entity to effect significant transactions such as large expenditures or contractual commitments, the construction or acquisition of assets, or the borrowing of money.
In addition, for the equity investments in which we have a minority ownership interest, we are unable to control ongoing operational decisions, including the incurrence of capital expenditures or additional indebtedness that we may be required to fund. Further, the other owners of our equity investments may establish reserves for working capital, capital projects, environmental matters, and legal proceedings, that would similarly reduce the amount of cash available for distribution. Any of the above could impact our ability to make cash distributions to our unitholders adversely.
Further, in connection with the acquisition of our membership interest in Chipeta, we became party to the Chipeta LLC agreement. Among other things, the Chipeta LLC agreement provides that to the extent available, Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, to its members quarterly in accordance with those members’ membership interests. Accordingly, we are required to distribute a portion of Chipeta’s cash balances, which are included in the cash balances in our consolidated balance sheets, to the other Chipeta member.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we therefore are, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in gathering, processing, compressing, treating, and transporting natural gas, crude oil, NGLs, and produced water, including (i) damage to our assets and surrounding properties and disruption of our operations as a result of weather, natural disasters, or acts of terrorism; (ii) inadvertent damage from construction, farm, and utility equipment; (iii) leaks or losses of hydrocarbons or produced water; (iv) fires and explosions; and (v) 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.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural-resource damage. These risks also may result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks that may occur in our business. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.

RISKS INHERENT IN AN INVESTMENT IN US

A reduction in Occidental’s ownership interest in us may reduce its incentive to support our operations.
As discussed in WES and WES Operating’s Relationship with Occidental Petroleum Corporation in Part I, Items 1 and 2 of this Form 10-K, we believe that one of our principal strengths is our affiliation with Occidental and that Occidental, through its significant economic interest in us, will continue to pursue projects that enhance the value of our business. To the extent Occidental’s net interest in us declines through the sale of its holdings or otherwise, Occidental may be less incentivized to support the continued growth of our business. Accordingly, a decrease in
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Occidental’s net holdings in us could have a material adverse effect on our business, results of operations, financial position, and ability to grow or make cash distributions to our unitholders.
Our general partner’s liability regarding our obligations is limited.
Our general partner has included provisions in its and our contractual arrangements that limit its liability so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may, therefore, cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner otherwise would be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner only to consider the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions.
Furthermore, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our 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, in the absence of bad faith, 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 approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
The general partner interest in us may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, Occidental, the owner of our general partner, may transfer its ownership interest in our general partner to a third party, also without unitholder consent. Our new general partner or the new owner of our general partner would then be in a position to replace the Board and officers of our general partner and to control the decisions taken by the Board and officers.
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity
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securities of equal or senior rank will dilute our existing unitholders’ ownership interests and voting strength, and may reduce the market price for our common units and cash available for distribution or increase the ratio of taxable income to distributions.
The market price of our common units could be affected adversely by sales of substantial amounts of our common units in the public or private markets, including sales by Occidental or other large holders.
We had 402,993,919 common units outstanding as of December 31, 2021. Occidental currently holds 200,281,578 common units, representing 49.7% of our outstanding common units. Occidental’s shelf registration statement currently allows for the offer and sale of approximately 30.3 million common units, or 7.5% of our common units as of December 31, 2021, from time to time. Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the impermissible distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that 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.

TAX RISKS TO COMMON UNITHOLDERS

Our taxation as a flow-through entity depends on our status as a partnership for U.S. federal income tax purposes, and our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be reduced substantially.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Notwithstanding our status as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as us to be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement and is not treated as an investment company. Based on our current operations, we believe that we satisfy the qualifying income requirement and are not treated as an investment company. Failing to meet the qualifying income requirement, being treated as an investment company, a change in our business activities, or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.
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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the applicable corporate tax rate and likely would pay state income tax at varying rates. Distributions to our unitholders generally would be taxed as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. If we are subject to corporate taxation, our cash available for distribution to our unitholders would be reduced substantially. Likewise, our treatment as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income or franchise taxes or other forms of taxation. For example, we are required to pay Texas margin tax on our gross income apportioned to Texas. Imposition of similar taxes on us in other jurisdictions in which we operate, or to which we may expand our operations, could reduce the cash available for distribution to our unitholders substantially.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The current U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial interpretation at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS were to contest the federal income tax positions we take, it may impact the market for our common units adversely, and the costs of any such contest would reduce the cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to the pricing of our related-party agreements with Occidental or our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made that such election will be practical, permissible, or effective in all circumstances. As a result, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders might be substantially reduced.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes on their share of our taxable income irrespective of whether they receive cash distributions from us. Unitholders may not receive cash distributions from us
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equal to their share of our taxable income or even equal to the actual tax liability attributable to their share of our taxable income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to that unitholder, if that unitholder sells such units at a price greater than that unitholder’s tax basis in those units, even if the price received is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units, unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans, and individual retirement accounts (or “IRAs”) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Additionally, distributions to non-U.S. unitholders will be reduced by withholding taxes at the highest applicable effective tax rate.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Treasury regulations and recent Treasury guidance further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs on or prior to December 31, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Non-U.S. unitholders should consult their tax advisor before investing in our common units.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based on the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based on the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets, and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss, and deduction. The IRS may challenge these methodologies or the resulting allocations, which could affect the value of our common units adversely.
In determining items of income, gain, loss, and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers
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regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss, and deduction.
A successful IRS challenge to these methods or allocations could diminish the amount of tax benefits available to our unitholders, affect the timing for recognition of these tax benefits or the amount of gain from any sale of common units, impact the value of our common units negatively, or result in audit adjustments to unitholders’ tax returns.
Our unitholders are subject to state and local taxes and return-filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, our unitholders are subject to other taxes, including foreign, state, and local taxes; unincorporated business taxes; and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders likely will be required to file tax returns and pay taxes in some or all of these various jurisdictions, or be subject to penalties for failure to comply with those requirements.

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Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

On July 1, 2020, the U.S. Department of Justice, on behalf of the U.S. Environmental Protection Agency (the “EPA”), and the State of Colorado commenced an enforcement action in the United States District Court for the District of Colorado against Kerr-McGee Gathering LLC (“KMG”), a wholly owned subsidiary of WES, for alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act (“LDAR requirements”) at its Fort Lupton facility in the DJ Basin complex. KMG previously had been in negotiations with the EPA and the State of Colorado to resolve the alleged non-compliance at the Fort Lupton facility. Per the complaint, plaintiffs pray for injunctive relief, remedial action, and civil penalties. Management cannot reasonably estimate the outcome of this action at this time.
On August 12, 2019, Sanchez Energy Corporation and certain of its affiliated companies (collectively, “Sanchez”) filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. While Sanchez holds a working interest in the acreage dedicated to our Springfield system, Sanchez also was the upstream operator for substantially all of the natural gas, crude oil, and NGLs that the Springfield system gathers and that WES processes in the Eagle Ford Shale Play. On April 29, 2020, we received notice that Sanchez filed a motion to reject a number of midstream and downstream agreements with commercial counterparties, including Sanchez’s Springfield gathering agreements and agreements obligating Sanchez to deliver the gas volumes gathered by the Springfield system to our Brasada processing plant. We objected to Sanchez’s rejection and instituted an adversary proceeding regarding such rejection. On May 15, 2020, Gavilan Resources LLC (“Gavilan”), an entity that owns a 25% working interest in the acreage where the Springfield gathering system and Brasada processing plant are located, also filed for Chapter 11 bankruptcy protection. As a part of this bankruptcy, Mesquite Energy, Inc. (the successor to Sanchez) (“Mesquite”) purchased Gavilan’s assets at auction. Gavilan did not assume and assign its agreements with Springfield as part of its asset sale. The parties reached a comprehensive legal and commercial settlement of these disputes in December 2021.
On October 29, 2020, WGR Operating, LP (“WGR”), on behalf of itself and derivatively on behalf of Mont Belvieu JV, filed suit against Enterprise Products Operating, LLC (“Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas. Our lawsuit seeks a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between Mont Belvieu JV (of which WGR is a 25% owner) and Enterprise (the “Operating Agreement”) related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas. Specifically, the Operating Agreement sets forth a revenue allocation structure, whereby revenue would be allocated to the various fracs at the Mont Belvieu complex in sequential order, with Fracs VII and VIII (which are owned by Mont Belvieu JV) following Fracs I through VI, but preceding any “Later Frac Facilities.” Subsequent to the construction of Fracs VII and VIII, Enterprise built Fracs IX, X, and XI, which it wholly owns, and has signaled its intention to treat such subsequent fracs as outside the Mont Belvieu revenue allocation. We do not believe Enterprise’s attempt to bypass the agreed-to revenue allocation is proper under the parties’ agreements and now seek judicial determination. We currently sue only for declaratory judgment to avoid potential future damages. We cannot make any assurances regarding the ultimate outcome of this proceeding and its resulting impact on WGR or WES.
Except as discussed above, we are not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of business. Management believes that there are no such proceedings for which a final disposition could have a material adverse effect on results of operations, cash flows, or financial condition, or for which disclosure is otherwise required by Item 103 of Regulation S-K.
    
Item 4.  Mine Safety Disclosures

Not applicable.
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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

MARKET INFORMATION

Our common units are listed on the NYSE under the symbol “WES.” As of February 17, 2022, there were 21 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We also have 9,060,641 general partner units issued and outstanding; there is no established public trading market for any such general partner units. All general partner units are held by our general partner.

OTHER SECURITIES MATTERS

Securities authorized for issuance under equity compensation plans. Our general partner has the authority to grant equity compensation awards to our independent directors, executive officers, and employees under (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “2012 LTIP”), (ii) the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “2017 LTIP,” assumed by the Partnership in connection with the Merger), and (iii) the Western Midstream Partners, LP 2021 Long-Term Incentive Plan (the “2021 LTIP”). The 2012 LTIP, the 2017 LTIP, and the 2021 LTIP permit the issuance of up to 3,000,000, 3,431,251, and 9,500,000 units, respectively, of which 484,909, 2,308,578, and 9,500,000 units, respectively, remained available for future issuance as of December 31, 2021. Read the information under Part III, Item 12 of this Form 10-K, which is incorporated by reference into this Item 5. See Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Purchases of equity securities by the issuer and affiliated persons. The following table sets forth information with respect to repurchases made by WES of its common units in the open market or in privately negotiated transactions under the Purchase Program during the fourth quarter of 2021:
PeriodTotal number of units purchasedAverage price paid per unit
Total number of units purchased as part of publicly announced plans or programs (1)
Approximate dollar value of units that may yet be purchased under the plans or programs (1)
October 1-31, 2021143,033 $20.99 143,033 $110,098,000 
November 1-30, 2021417,493 20.70 417,493 101,456,000 
December 1-31, 20215,060,924 20.05 5,060,924 — 
Total5,621,450 20.12 5,621,450 
______________________________________________________________________________________
(1)In November 2020, WES announced the Purchase Program, pursuant to which we may purchase up to $250.0 million in aggregate value of our common units through December 31, 2021. As of December 31, 2021, the entire $250.0 million authorized program had been fulfilled. The above table includes units repurchased from Occidental, see Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.
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SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Available cash. Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) to unitholders of record on the applicable record date within 55 days following each quarter’s end. The amount of available cash generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the general partner to provide for the proper conduct of our business, including (i) reserves to fund future capital expenditures; (ii) to comply with applicable laws, debt instruments, or other agreements; or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement and are intended to be repaid or refinanced within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund unitholder distributions.

General partner interest. As of December 31, 2021, our general partner owned a 2.2% general partner interest in us, which entitles it to receive cash distributions. Our general partner may own our common units or other equity securities and would be entitled to receive cash distributions on any such interests.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K.
The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2021 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental.

EXECUTIVE SUMMARY

We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania. As of December 31, 2021, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities37 3 — — 
Natural-gas processing plants/trains
24 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines
5 — — 1 
Crude-oil pipelines
3 1 — 4 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

Significant financial and operational events during the year ended December 31, 2021, included the following:

•WES Operating redeemed the total principal amount outstanding of $431.1 million of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture.

•WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer.

•We repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million.

•Our fourth-quarter 2021 per-unit distribution of $0.32700 increased $0.004 from the third-quarter 2021 per-unit distribution of $0.32300.

•Natural-gas throughput attributable to WES totaled 4,148 MMcf/d for the year ended December 31, 2021, representing a 3% decrease compared to the year ended December 31, 2020.

•Crude-oil and NGLs throughput attributable to WES totaled 659 MBbls/d for the year ended December 31, 2021, representing a 6% decrease compared to the year ended December 31, 2020.

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•Produced-water throughput attributable to WES totaled 703 MBbls/d for the year ended December 31, 2021, representing a 1% increase compared to the year ended December 31, 2020.

•Gross margin was $2.0 billion for the year ended December 31, 2021, representing a 4% decrease compared to the year ended December 31, 2020. See Key Performance Metrics within this Item 7.

•Adjusted gross margin for natural-gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $1.24 per Mcf for the year ended December 31, 2021, representing a 7% increase compared to the year ended December 31, 2020.

•Adjusted gross margin for crude-oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $2.28 per Bbl for the year ended December 31, 2021, representing a 10% decrease compared to the year ended December 31, 2020.

•Adjusted gross margin for produced-water assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.93 per Bbl for the year ended December 31, 2021, representing a 5% decrease compared to the year ended December 31, 2020.

The following table provides additional information on throughput for the periods presented below:
Year Ended December 31,
20212020Inc/
(Dec)		2019Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin1,256 1,297 (3)%1,226 6 %
DJ Basin1,369 1,305 5 %1,236 6 %
Equity investments463 445 4 %398 12 %
Other1,215 1,386 (12)%1,563 (11)%
Total throughput for natural-gas assets
4,303 4,433 (3)%4,423 — %
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin183 189 (3)%150 26 %
DJ Basin90 101 (11)%118 (14)%
Equity investments366 381 (4)%343 11 %
Other33 41 (20)%52 (21)%
Total throughput for crude-oil and NGLs assets
672 712 (6)%663 7 %
Throughput for produced-water assets (MBbls/d)
Delaware Basin717 712 1 %556 28 %
Total throughput for produced-water assets
717 712 1 %556 28 %

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OUR OPERATIONS

Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather and dispose of produced water.
We operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains. For example, for the year ended December 31, 2021, our West Texas and DJ Basin assets provided (i) 47% and 35%, respectively, of Total revenues and other, (ii) 33% and 36%, respectively, each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 60% and 29%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.
For the year ended December 31, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payment, and/or cost-of-service commitments under certain of our contracts.
For the year ended December 31, 2021, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.
We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to delay drilling or shut-in production in certain areas, which would reduce the volumes of hydrocarbons available to our systems. We also bear limited commodity-price risk through the settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K.
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HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, and (iv) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see in Key Performance Metrics within this Item 7).

Throughput. Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities. Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, fleet management, contract services, utility costs, and services provided to us or on our behalf.

General and administrative expenses. To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Commodity purchase and sale agreements. Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership. Accordingly, we no longer recognize service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC. Year-over-year variances for the year ended December 31, 2021, include the following impacts related to this change (i) decrease of $45.9 million in Service revenues – fee based, (ii) decrease of $21.2 million in Product sales, and (iii) decrease of $67.1 million in Cost of product expense. Year-over-year variances for the year ended December 31, 2020, include the following impacts related to this change (i) decrease of $130.9 million in Service revenues – fee based, (ii) decrease of $29.7 million in Product sales, and (iii) decrease of $160.6 million in Cost of product expense. These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see Key Performance Metrics within this Item 7). See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


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Weather-related impacts. In February 2021, the U.S. experienced winter storm Uri, bringing extreme cold temperatures, ice, and snow to the central U.S., including Texas, and in March 2021, Colorado experienced a historic blizzard. Winter storm Uri adversely affected our volumes for approximately ten days and the blizzard in Colorado likewise disrupted our assets in that state. We estimate the impact of these weather events reduced our net income and Adjusted EBITDA (as defined under the caption Key Performance Metrics within this Item 2) for the year ended December 31, 2021, by approximately $30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities.

Impairments. We recognized long-lived asset and other impairments of $30.5 million, $203.9 million, and $6.3 million for the years ended December 31, 2021, 2020, and 2019, respectively. During the year ended December 31, 2020, we also recognized a goodwill impairment of $441.0 million, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero.
For a description of impairments recorded, see Note 9—Property, Plant, and Equipment, Note 7—Equity Investments, and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses. On December 31, 2019, we entered into the December 2019 Agreements, which helped facilitate our ability to operate more independently from Occidental. As a result, beginning in 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Noncontrolling interests. For periods subsequent to Merger completion, our noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating. For periods prior to Merger completion, our noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, and (iv) the Class C units issued by WES Operating to a subsidiary of Anadarko as part of the funding for the acquisition of DBM.

Acquisitions and divestitures. In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located in Northeast Wyoming, to a third party.
During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed. We received total proceeds of $8.0 million, $7.0 million in the fourth quarter of 2020 and $1.0 million when the sale closed in the second quarter of 2021, resulting in a net gain on sale of $5.4 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
In February 2019, WES Operating acquired AMA from Anadarko. In January 2019, we acquired a 30% interest in Red Bluff Express.
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:
Year Ended December 31,
thousands202120202019
Total revenues and other (1)
$2,877,155 $2,772,592 $2,746,174 
Equity income, net – related parties204,645 226,750 237,518 
Total operating expenses (1)
1,745,573 2,129,063 1,750,943 
Gain (loss) on divestiture and other, net44 8,634 (1,406)
Operating income (loss)1,336,271 878,913 1,231,343 
Interest income – Anadarko note receivable— 11,736 16,900 
Interest expense(376,512)(380,058)(303,286)
Gain (loss) on early extinguishment of debt(24,944)11,234 — 
Other income (expense), net(623)1,025 (123,785)
Income (loss) before income taxes934,192 522,850 821,172 
Income tax expense (benefit)(9,807)5,998 13,472 
Net income (loss)943,999 516,852 807,700 
Net income (loss) attributable to noncontrolling interests27,707 (10,160)110,459 
Net income (loss) attributable to Western Midstream Partners, LP (2)
$916,292 $527,012 $697,241 
_________________________________________________________________________________________
(1)Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, and NGLs to related parties. Total operating expenses includes amounts charged by related parties for services received. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2021” refer to the comparison of the year ended December 31, 2021, to the year ended December 31, 2020, and any increases or decreases “for the year ended December 31, 2020” refer to the comparison of the year ended December 31, 2020, to the year ended December 31, 2019.
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Throughput
Year Ended December 31,
20212020Inc/
(Dec)		2019Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation466 543 (14)%528 3 %
Processing3,374 3,445 (2)%3,497 (1)%
Equity investments (1)
463 445 4 %398 12 %
Total throughput4,303 4,433 (3)%4,423 — %
Throughput attributable to noncontrolling interests (2)
155 159 (3)%175 (9)%
Total throughput attributable to WES for natural-gas assets
4,148 4,274 (3)%4,248 1 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation306 331 (8)%320 3 %
Equity investments (3)
366 381 (4)%343 11 %
Total throughput672 712 (6)%663 7 %
Throughput attributable to noncontrolling interests (2)
13 14 (7)%13 8%
Total throughput attributable to WES for crude-oil and NGLs assets
659 698 (6)%650 7 %
Throughput for produced-water assets (MBbls/d)
Gathering and disposal717 712 1 %556 28 %
Throughput attributable to noncontrolling interests (2)
14 14 — %11 27 %
Total throughput attributable to WES for produced-water assets
703 698 1 %545 28 %
_________________________________________________________________________________________
(1)Represents the 14.81% share of average Fort Union throughput (until divested in October 2020), 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.
(2)For all periods presented, includes (i) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.
(3)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.

Natural-gas assets

Gathering, treating, and transportation throughput decreased by 77 MMcf/d for the year ended December 31, 2021, primarily due to (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021 and (ii) production declines and the impact of winter storm Uri at the Springfield gas-gathering system. These decreases were offset partially by increased production in areas around the Marcellus Interest systems.
Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year ended December 31, 2020, primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison treating facility and Springfield gas-gathering system.
Processing throughput decreased by 71 MMcf/d for the year ended December 31, 2021, primarily due to (i) lower production and the impact of winter storm Uri at the West Texas complex, (ii) the Granger straddle plant being held idle beginning in the third quarter of 2020, and (iii) lower volumes at the Granger and Brasada complexes due to production declines in the areas. These decreases were offset partially by higher volumes at the DJ Basin complex primarily due to an additional third-party connection to Latham Train II beginning January 1, 2021.

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Processing throughput decreased by 52 MMcf/d for the year ended December 31, 2020, primarily due to (i) third-party volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 and the plant being held idle during the third and fourth quarters of 2020, (ii) lower throughput at the Chipeta complex due to production declines in the area and a third-party contract that terminated during the fourth quarter of 2019, and (iii) lower throughput at the Red Desert complex due to production declines in the area. These decreases were offset partially by (i) increased production in areas around the West Texas and DJ Basin complexes, (ii) the start-up of Latham Train II at the DJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at the West Texas complex in March 2019.
Equity-investment throughput increased by 18 MMcf/d for the year ended December 31, 2021, primarily due to increased volumes on Red Bluff Express and at the Mi Vida plant, partially offset by (i) decreased volumes at the Rendezvous system due to production declines in the area and (ii) decreased volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020.
Equity-investment throughput increased by 47 MMcf/d for the year ended December 31, 2020, primarily due to increased volumes on Red Bluff Express resulting from increased production in the area. This increase was offset partially by (i) decreased third-party volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the Rendezvous system due to production declines in the area.

Crude-oil and NGLs assets

Gathering, treating, and transportation throughput decreased by 25 MBbls/d for the year ended December 31, 2021, primarily due to (i) lower volumes at the DJ Basin and Springfield oil systems resulting from production declines in the areas and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri.
Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2020, primarily due to increased throughput at the DBM oil system with the commencement of Loving ROTF Trains III and IV operations during the first and third quarters of 2020, respectively, and increased production, partially offset by lower throughput at the DJ Basin oil system due to production declines in the area.
Equity-investment throughput decreased by 15 MBbls/d for the year ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline.
Equity-investment throughput increased by 38 MBbls/d for the year ended December 31, 2020, primarily due to (i) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by decreased volumes on the Whitethorn pipeline.

Produced-water assets

Gathering and disposal throughput increased by 5 MBbls/d for the year ended December 31, 2021, due to increased volumes at the DBM water systems resulting from (i) higher production in the area, primarily during the second half of 2021, and (ii) new third-party connections brought online during the fourth quarter of 2021. These increases were offset partially by the impact of winter storm Uri.
Gathering and disposal throughput increased by 156 MBbls/d for the year ended December 31, 2020, due to increased throughput at the DBM water systems resulting from additional (i) production, (ii) water-disposal facilities, and (iii) offload connections that increased capacity of the systems.


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Service Revenues
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Service revenues – fee based$2,462,835 $2,584,323 (5)%$2,388,191 8 %
Service revenues – product based122,584 48,369 153 %70,127 (31)%
 Total service revenues$2,585,419 $2,632,692 (2)%$2,458,318 7 %

Service revenues – fee based

Service revenues – fee based decreased by $121.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $45.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $36.4 million at the DBM oil system due to decreased throughput, including the impact of winter storm Uri, and lower lease revenue under the operating and maintenance agreement with Occidental, (iii) $23.4 million at the DJ Basin oil system due to an annual cost-of-service rate adjustment made during the fourth quarter of 2021 and decreased throughput, partially offset by a higher average gathering fee, (iv) $19.0 million at the DJ Basin complex due to decreased throughput on certain fee-based contracts, (v) $17.0 million at the Bison treating facility due to the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020, decreased throughput, and the sale of the facility to a third party during the second quarter of 2021, and (vi) $14.3 million at the DBM water systems due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, partially offset by increased throughput. These decreases were offset partially by increases of (i) $26.6 million at the West Texas complex due to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, partially offset by decreased throughput, including the impact of winter storm Uri, and (ii) $13.1 million at the Springfield system due to cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost-of-service rate effective January 1, 2021.
Service revenues – fee based increased by $196.1 million for the year ended December 31, 2020, primarily due to increases of (i) $98.1 million at the West Texas complex and $97.9 million at the DJ Basin complex from increased throughput, (ii) $63.6 million at the DBM oil system from increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, (iii) $59.3 million at the DBM water systems from increased throughput, and (iv) $21.4 million at the Springfield system due to annual cost-of-service rate adjustments that increased revenue in the fourth quarter of 2020 and decreased revenue in the fourth quarter of 2019, partially offset by decreased volumes. These increases were offset partially by a decrease of $130.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

Service revenues – product based

Service revenues – product based increased by $74.2 million for the year ended December 31, 2021, primarily due to increases of (i) $22.2 million at the West Texas complex due to an increase in electricity-related fees charged to customers during winter storm Uri, (ii) $20.5 million at the DJ Basin complex due to increased third-party volumes and average prices, and (iii) $8.9 million at the Granger complex, $8.5 million at the Hilight system, $6.9 million at the Chipeta complex, and $5.3 million at the MGR assets due to increased prices.
Service revenues – product based decreased by $21.8 million for the year ended December 31, 2020, primarily due to (i) decreased third-party volumes at the DJ Basin complex and MGR assets and (ii) decreased pricing across several systems.

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Product Sales
Year Ended December 31,
thousands except percentages and per-unit amounts20212020Inc/
(Dec)		2019Inc/
(Dec)
Natural-gas sales
$83,102 $30,527 172 %$66,557 (54)%
NGLs sales207,845 108,032 92 %219,831 (51)%
Total Product sales$290,947 $138,559 110 %$286,388 (52)%
Per-unit gross average sales price:
Natural gas (per Mcf)$4.31 $1.45 197 %$1.65 (12)%
NGLs (per Bbl)33.69 13.14 156 %20.93 (37)%

Natural-gas sales

Natural-gas sales increased by $52.6 million for the year ended December 31, 2021, primarily due to increases of (i) $49.0 million at the West Texas complex attributable to an increase in average prices, (ii) $9.6 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes sold, and (iii) $1.8 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). These increases were offset partially by decreases of $5.6 million at the DJ Basin complex and $4.9 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices.
Natural-gas sales decreased by $36.0 million for the year ended December 31, 2020, primarily due to decreases of (i) $15.2 million at the DJ Basin complex attributable to a decrease in average prices, (ii) $9.8 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (iii) $6.2 million at the Hilight system resulting from an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown, and (iv) $2.6 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

NGLs sales

NGLs sales increased by $99.8 million for the year ended December 31, 2021, primarily due to increases of (i) $73.8 million at the West Texas complex attributable to an increase in average prices, partially offset by a decrease in volumes sold, (ii) $22.3 million at the Chipeta complex and $11.3 million at the Granger complex attributable to increases in average prices, and (iii) $6.5 million at the DJ Basin complex attributable to an increase in average prices and volumes sold. These increases were offset partially by a decrease of $23.0 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
NGLs sales decreased by $111.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $34.0 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (ii) $27.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (iii) $17.7 million at the DJ Basin complex attributable to a decrease in average prices, and (iv) $14.7 million at the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average prices and volumes sold.


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Equity Income, Net – Related Parties
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Equity income, net – related parties$204,645 $226,750 (10)%$237,518 (5)%

Equity income, net – related parties decreased by $22.1 million for the year ended December 31, 2021, primarily due to decreases of (i) $30.8 million at Whitethorn LLC related to commercial activities and lower volumes, (ii) $4.7 million at White Cliffs due to lower volumes, and (iii) $4.0 million at Cactus II due to an increase in depreciation expense recorded in 2021. These decreases were offset partially by increases of (i) $8.1 million at Mont Belvieu JV primarily from a load-reduction electricity credit received in the second quarter of 2021 related to winter storm Uri and (ii) $5.3 million and $4.6 million at Red Bluff Express and Saddlehorn, respectively, resulting from increased volumes.
Equity income, net – related parties decreased by $10.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $38.8 million from Whitethorn LLC related to commercial activities and decreased volumes and (ii) $4.2 million from decreased rates at White Cliffs. These decreases were offset partially by increases of (i) $11.4 million related to the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) $5.5 million at TEP, $5.3 million at Ranch Westex, $5.1 million at FRP, and $5.1 million at Red Bluff Express resulting from increased volumes.

Cost of Product and Operation and Maintenance Expenses
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Residue purchases$146,673 $65,193 125 %$100,570 (35)%
NGLs purchases160,662 131,964 22 %331,872 (60)%
Other14,950 (9,069)NM11,805 (177)%
Cost of product322,285 188,088 71 %444,247 (58)%
Operation and maintenance581,300 580,874 — %641,219 (9)%
Total Cost of product and Operation and maintenance expenses$903,585 $768,962 18 %$1,085,466 (29)%
_________________________________________________________________________________________
NM—Not meaningful

Residue purchases

Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.6 million at the West Texas complex, $6.7 million at the Chipeta complex, and $6.3 million at the Hilight system attributable to increases in average prices and (ii) $9.2 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $5.2 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
Residue purchases decreased by $35.4 million for the year ended December 31, 2020, primarily due to decreases of (i) $21.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $11.3 million at the DJ Basin complex attributable to average-price decreases, and (iii) $4.3 million at the MGR assets attributable to average-price and purchased-volume decreases. These decreases were offset partially by an increase of $3.2 million at the Chipeta complex primarily due to purchased-volume and average-price increases.


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NGLs purchases

NGLs purchases increased by $28.7 million for the year ended December 31, 2021, primarily due to increases of (i) $40.4 million at the West Texas complex, $13.7 million at the Chipeta complex, and $8.2 million at the Granger complex attributable to increases in average prices, (ii) $21.5 million at the DJ Basin complex attributable to an increase in average prices and volumes purchased, and (iii) $4.1 million at the Brasada complex attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $61.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
NGLs purchases decreased by $199.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $139.5 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $32.6 million at the West Texas complex attributable to average-price decreases, partially offset by purchased-volume increases, (iii) $13.8 million at the Brasada complex attributable to purchased-volume decreases, partially offset by average-price increases, and (iv) $6.9 million at the Chipeta complex attributable to average-price and purchased-volume decreases.

Other items

Other items increased by $24.0 million for the year ended December 31, 2021, primarily due to increases of $29.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions, partially offset by a decrease of $11.7 million at the DJ Basin complex due to changes in imbalance positions.
Other items decreased by $20.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $10.3 million at the West Texas complex due to changes in imbalance positions and (ii) $10.0 million at the DJ Basin complex due to a decrease in transportation costs and changes in imbalance positions.

Operation and maintenance expense

Operation and maintenance expense increased by $0.4 million for the year ended December 31, 2021, primarily due to an increase of $7.6 million at the West Texas complex, mainly attributable to increased field-related expenses, as well as an increase in utilities expense resulting from the impact of winter storm Uri, partially offset by a decrease of $6.6 million at the Springfield system primarily due to decreased environmental and regulatory expenses.
Operation and maintenance expense decreased by $60.3 million for the year ended December 31, 2020, primarily as a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $34.2 million at the West Texas complex primarily resulting from decreased salaries and wages, contract labor and consulting services, and surface maintenance and plant repairs expense, (ii) $6.1 million and $3.3 million at the Springfield and DBM oil systems, respectively, primarily due to decreased salaries and wages and surface maintenance and plant repairs expense, partially offset by increases in other field expenses, (iii) $4.6 million at the Chipeta complex primarily attributable to decreased surface maintenance and plant repairs and utilities expense, and (iv) $3.2 million and $2.4 million at the Hilight system and Granger complex, respectively, primarily due to decreased salaries and wages, surface maintenance and plant repairs, and safety expense.


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Other Operating Expenses
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
General and administrative$195,549 $155,769 26 %$114,591 36 %
Property and other taxes64,267 68,340 (6)%61,352 11 %
Depreciation and amortization551,629 491,086 12 %483,255 2 %
Long-lived asset and other impairments
30,543 203,889 (85)%6,279 NM
Goodwill impairment— 441,017 (100)%— NM
Total other operating expenses$841,988 $1,360,101 (38)%$665,477 104 %

General and administrative expenses

General and administrative expenses increased by $39.8 million for the year ended December 31, 2021, primarily due to increases of (i) $23.7 million in personnel costs, including increased bonus-related contributions under our employee savings plan and equity-based compensation expense, and (ii) $16.9 million in contract and consulting costs primarily related to information technology services and fees.
General and administrative expenses increased by $41.2 million for the year ended December 31, 2020, primarily due to (i) $21.2 million related to information technology services provided by Occidental to WES and (ii) $16.4 million in personnel costs primarily resulting from WES securing its own dedicated workforce as of December 31, 2019. General and administrative expenses also increased by $6.0 million for the year ended December 31, 2020, primarily due to increases in corporate expenses and professional fees. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
For the year ended December 31, 2019, General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements. Effective with the December 2019 Agreements, WES began to incur such costs directly, or via direct charge from Occidental, pursuant to the terms of the Services Agreement.

Property and other taxes

Property and other taxes decreased by $4.1 million for the year ended December 31, 2021, primarily due to ad valorem tax decreases at the West Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in the DJ Basin due to higher tax rates.
Property and other taxes increased by $7.0 million for the year ended December 31, 2020, primarily due to ad valorem tax increases of $6.5 million at the DJ Basin complex due to capital projects being placed into service, including the completion of Latham Train I in November 2019. This increase was offset partially by ad valorem tax decreases in Utah and West Texas due to lower valuations and lower tax rates.

Depreciation and amortization expense

Depreciation and amortization expense increased by $60.5 million for the year ended December 31, 2021, primarily due to increases of (i) $33.6 million at the DJ Basin complex, primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system in the comparative prior period, (ii) $13.2 million at the Hilight system due to revisions in cost estimates related to asset retirement obligations, (iii) $8.2 million related to depreciation for capitalized information technology implementation costs related to the stand-up of WES as an independent organization, (iv) $7.3 million at the MGR assets due to an acceleration of depreciation expense, as well as revisions in cost estimates related to asset retirement obligations, and (v) $7.2 million at the West Texas complex resulting from capital projects being placed into service. These increases were offset partially by a decrease of $17.4 million due to the sale of the Bison treating facility in the second quarter of 2021.


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Depreciation and amortization expense increased by $7.8 million for the year ended December 31, 2020, primarily due to increases of (i) $11.9 million and $5.9 million at the West Texas complex and DBM oil system, respectively, resulting from capital projects being placed into service, (ii) $7.8 million of amortization expense related to finance leases, and (iii) $3.3 million for a pipeline in Wyoming due to revisions in cost estimates related to asset retirement obligations. These amounts were offset partially by decreases of (i) $10.6 million at the DJ Basin complex primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system of $32.7 million, offset by increased depreciation expense of $22.1 million for capital projects being placed into service, (ii) $10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii) $5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020. See Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations.

Long-lived asset and other impairment expense

Long-lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex.
Long-lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects.
Long-lived asset and other impairment expense for the year ended December 31, 2019, was primarily due to impairments of $4.9 million at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects.
For further information on Long-lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Goodwill impairment expense

During the three months ended March 31, 2020, an interim goodwill impairment test was performed due to significant unit-price declines triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption. As a result of the interim impairment test, a goodwill impairment of $441.0 million was recognized for the gathering and processing reporting unit. For additional information, see Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Interest Income – Anadarko Note Receivable and Interest Expense

Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Interest income – Anadarko note receivable$— $11,736 (100)%$16,900 (31)%
Third parties
Long-term and short-term debt
$(366,570)$(369,815)(1)%$(315,872)17 %
Finance lease liabilities(861)(1,510)(43)%— NM
Commitment fees and amortization of debt-related costs(12,705)(13,501)(6)%(12,424)9 %
Capitalized interest3,624 4,774 (24)%26,980 (82)%
Related parties
APCWH Note Payable— — — %(1,833)(100)%
Finance lease liabilities— (6)(100)%(137)(96)%
Interest expense$(376,512)$(380,058)(1)%$(303,286)25 %

Interest income

Interest income - Anadarko note receivable decreased by $11.7 million and $5.2 million for the years ended December 31, 2021 and 2020, respectively, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Interest expense

Interest expense decreased by $3.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $21.2 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 on March 1, 2021, (ii) $5.7 million due to lower outstanding balances on the 4.000% Senior Notes due 2022, Floating Rate Notes due 2023, 3.950% Senior Notes due 2025, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021, and (iii) $3.6 million due to lower outstanding borrowings under the RCF in 2021. These decreases were offset partially by (i) an increase of $26.4 million in additional interest incurred from higher effective interest rates resulting from credit-rating downgrades on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and (ii) a decrease of $1.2 million in capitalized interest due to decreased capital expenditures.
Interest expense increased by $76.8 million for the year ended December 31, 2020, primarily due to (i) $150.9 million of interest incurred on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and Floating-Rate Senior Notes due 2023 that were issued in January 2020 and (ii) a decrease of $22.2 million in capitalized interest due to decreased capital expenditures. These increases were offset partially by decreases of (i) $75.0 million that occurred as a result of the repayment and termination of the Term loan facility in January 2020 and (ii) $15.5 million due to lower outstanding borrowings under the RCF in 2020.
See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.


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Other Income (Expense), Net
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Other income (expense), net$(623)$1,025 (161)%$(123,785)(101)%

Other income (expense), net increased by $124.8 million for the year ended December 31, 2020, primarily due to non-cash losses of $125.3 million on interest-rate swaps incurred during the year ended December 31, 2019. All outstanding interest-rate swap agreements were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Income Tax Expense (Benefit)
Year Ended December 31,
thousands except percentages20212020Inc/
(Dec)		2019Inc/
(Dec)
Income (loss) before income taxes$934,192$522,85079 %$821,172(36)%
Income tax expense (benefit)(9,807)5,998NM13,472(55)%
Effective tax rateNM1 %2 %

We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax. Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.
For the year ended December 31, 2021, the variance from the federal statutory rate was primarily impacted by a state margin rate reduction associated with Occidental’s settlement of state audit matters and our Texas margin tax liability. For the year ended December 31, 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability.

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KEY PERFORMANCE METRICS
Year Ended December 31,
thousands except percentages and per-unit amounts20212020Inc/
(Dec)		2019Inc/
(Dec)
Adjusted gross margin for natural-gas assets
$1,882,726 $1,820,926 3 %$1,656,041 10 %
Adjusted gross margin for crude-oil and NGLs assets
547,134 647,390 (15)%578,100 12 %
Adjusted gross margin for produced-water assets
237,656 249,889 (5)%193,936 29 %
Adjusted gross margin2,667,516 2,718,205 (2)%2,428,077 12 %
Per-Mcf Adjusted gross margin for natural-gas assets (1)
1.24 1.16 7 %1.07 8 %
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (2)
2.28 2.54 (10)%2.44 4 %
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.93 0.98 (5)%0.97 1 %
Adjusted EBITDA1,946,690 2,030,366 (4)%1,719,090 18 %
Free cash flow1,490,128 1,226,588 21 %36,709 NM
_________________________________________________________________________________________
(1)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.
(2)Average for period. Calculated as Adjusted gross margin for crude-oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil and NGLs assets.
(3)Average for period. Calculated as Adjusted gross margin for produced-water assets, divided by total throughput (MBbls/d) attributable to WES for produced-water assets.

Adjusted gross margin. We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product. We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties. The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are reimbursed by certain customers (recorded as revenue with an offset recorded as Operation and maintenance expense).
To facilitate investor and industry analyst comparisons between us and our peers, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets.
Adjusted gross margin decreased by $50.7 million for the year ended December 31, 2021, primarily due to (i) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, (ii) a decrease in distributions from Whitethorn LLC and Cactus II, (iii) decreased throughput and an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), (iv) the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020 and decreased throughput at the Bison treating facility, which was sold to a third party during the second quarter of 2021, (v) a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the DBM water systems, and (vi) decreased throughput on certain fee-based contracts at the DJ Basin complex. These decreases were offset partially by (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex, (ii) cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost-of-service rate effective January 1, 2021, at the Springfield system, and (iii) an increase in distributions from Red Bluff Express and Ranch Westex.

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Adjusted gross margin increased by $290.1 million for the year ended December 31, 2020, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes and the DBM water systems, (ii) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system, (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, (iv) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020, and (v) annual cost-of-service rate adjustments at the Springfield system that increased revenues in the fourth quarter of 2020 and decreased revenues in the fourth quarter of 2019 (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC related to commercial activities and (ii) a decrease at the Hilight system resulting from lower throughput and an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.08 for the year ended December 31, 2021, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex and (ii) a higher cost-of-service rate effective January 1, 2021, at the Springfield system. These increases were offset partially by decreased throughput on certain fee-based contracts at the DJ Basin complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.09 for the year ended December 31, 2020, primarily due to increased throughput at the West Texas and DJ Basin complexes, which have higher-than-average per-Mcf margins as compared to our other natural-gas assets.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets decreased by $0.26 for the year ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system and (ii) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets. These decreases were offset partially by a higher cost-of-service rate effective January 1, 2021, at the Springfield system.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.10 for the year ended December 31, 2020, primarily due to (i) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by a decrease in distributions from Whitethorn LLC related to commercial activities.
Per-Bbl Adjusted gross margin for produced-water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non-cash equity-based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following:

•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

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

Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments. These amounts were offset partially by (i) a $104.6 million increase in total revenues and other and (ii) a $4.1 million decrease in property taxes.
Adjusted EBITDA increased by $311.3 million for the year ended December 31, 2020, primarily due to (i) a $256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a $60.3 million decrease in operation and maintenance expenses, (iii) a $26.4 million increase in total revenues and other, and (iv) a $14.0 million increase in distributions from equity investments. These amounts were offset partially by (i) a $33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a $7.0 million increase in property taxes.
The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

Free cash flow. We define “Free cash flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free cash flow an appropriate metric for assessing capital discipline, cost efficiency, and balance-sheet strength. Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period. Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes.
Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings.
Free cash flow increased by $1,189.9 million for the year ended December 31, 2020, primarily due to (i) a decrease of $765.7 million in capital expenditures, (ii) an increase of $313.3 million in net cash provided by operating activities, and (iii) a decrease of $109.0 million in contributions to equity investments.
See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

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Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure used by us that is most directly comparable to Adjusted gross margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to Free cash flow is net cash provided by operating activities. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted gross margin, Adjusted EBITDA, and Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.
Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results.
The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non-GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Free cash flow:
Year Ended December 31,
thousands202120202019
Reconciliation of Gross margin to Adjusted gross margin
Total revenues and other$2,877,155 $2,772,592 $2,746,174 
Less:
Cost of product322,285 188,088 444,247 
Depreciation and amortization551,629 491,086 483,255 
Gross margin2,003,241 2,093,418 1,818,672 
Add:
Distributions from equity investments254,901 278,797 264,828 
Depreciation and amortization551,629 491,086 483,255 
Less:
Reimbursed electricity-related charges recorded as revenues74,405 79,261 74,629 
Adjusted gross margin attributable to noncontrolling interests (1)
67,850 65,835 64,049 
Adjusted gross margin$2,667,516 $2,718,205 $2,428,077 
Adjusted gross margin for natural-gas assets
$1,882,726 $1,820,926 $1,656,041 
Adjusted gross margin for crude-oil and NGLs assets
547,134 647,390 578,100 
Adjusted gross margin for produced-water assets
237,656 249,889 193,936 
_________________________________________________________________________________________
(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.

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Year Ended December 31,
thousands202120202019
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)$943,999 $516,852 $807,700 
Add:
Distributions from equity investments254,901 278,797 264,828 
Non-cash equity-based compensation expense
27,676 22,462 14,392 
Interest expense376,512 380,058 303,286 
Income tax expense4,403 10,278 13,472 
Depreciation and amortization551,629 491,086 483,255 
Impairments (1)
30,543 644,906 6,279 
Other expense1,468 1,953 161,813 
Less:
Gain (loss) on divestiture and other, net44 8,634 (1,406)
Gain (loss) on early extinguishment of debt(24,944)11,234 — 
Equity income, net – related parties204,645 226,750 237,518 
Interest income – Anadarko note receivable— 11,736 16,900 
Other income585 2,785 37,792 
Income tax benefit14,210 4,280 — 
Adjusted EBITDA attributable to noncontrolling interests (2)
49,901 50,607 45,131 
Adjusted EBITDA$1,946,690 $2,030,366 $1,719,090 
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities$1,766,852 $1,637,418 $1,324,100 
Interest (income) expense, net376,512 368,322 286,386 
Uncontributed cash-based compensation awards— — (1,102)
Accretion and amortization of long-term obligations, net
(7,635)(8,654)(8,441)
Current income tax expense (benefit)(37)2,702 5,863 
Other (income) expense, net (3)
623 (1,025)(1,549)
Cash paid to settle interest-rate swaps
— 25,621 107,685 
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
Changes in assets and liabilities:
Accounts receivable, net(16,366)193,688 45,033 
Accounts and imbalance payables and accrued liabilities, net(114,887)(144,437)30,866 
Other items, net(49,856)(24,822)(54,876)
Adjusted EBITDA attributable to noncontrolling interests (2)
(49,901)(50,607)(45,131)
Adjusted EBITDA$1,946,690 $2,030,366 $1,719,090 
Cash flow information
Net cash provided by operating activities$1,766,852 $1,637,418 $1,324,100 
Net cash used in investing activities(257,538)(448,254)(3,387,853)
Net cash provided by (used in) financing activities(1,752,237)(844,204)2,071,573 
_________________________________________________________________________________________
(1)Includes goodwill impairment for the year ended December 31, 2020. See Note 10—Goodwill and Other Intangibles 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.
(3)Excludes net non-cash losses on interest-rate swaps of $25.6 million for the year ended December 31, 2019. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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Year Ended December 31,
thousands202120202019
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities$1,766,852 $1,637,418 $1,324,100 
Less:
Capital expenditures313,674 423,602 1,189,254 
Contributions to equity investments – related parties4,435 19,388 128,393 
Add:
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
Free cash flow$1,490,128 $1,226,588 $36,709 
Cash flow information
Net cash provided by operating activities$1,766,852 $1,637,418 $1,324,100 
Net cash used in investing activities(257,538)(448,254)(3,387,853)
Net cash provided by (used in) financing activities(1,752,237)(844,204)2,071,573 

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the below-described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results.

Impact of crude-oil, natural-gas, and NGLs prices. Crude-oil, natural-gas, and NGLs prices can fluctuate significantly, and have done so over time. Commodity-price fluctuations affect the level of our customers’ activities and our customers’ allocations of capital within their own asset portfolios. During the first quarter of 2020, oil and natural-gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in demand resulting from the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. These market dynamics had an adverse impact on producers that provide throughput into our systems, and we experienced decreased throughput at many of our locations. For example, NYMEX West Texas Intermediate crude-oil daily settlement prices during 2020 ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, and prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021. Although commodity prices have rebounded to pre-pandemic levels, the extent and duration of the recent commodity-price volatility cannot be predicted, and potential impacts to our business include the following:

•We have exposure to increased credit risk to the extent any of our customers, including Occidental, is in financial distress. See Liquidity and Capital Resources—Credit risk within this Item 7 for additional information.

•An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most-recent four-consecutive fiscal quarters ending on such day). See Liquidity and Capital Resources—Debt and credit facilities within this Item 7 for additional information.

•As of December 31, 2021, it is reasonably possible that future commodity-price declines, prolonged depression of commodity prices, changes to producers’ drilling plans in response to lower prices, and potential producer bankruptcies could result in future long-lived asset impairments.


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To the extent producers continue with development plans in our areas of operation, we intend to continue to connect new wells or production facilities to our systems to maintain throughput on our systems and mitigate the impact of production declines. However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers. Additionally, we intend to continue to evaluate the crude-oil, NGLs, and natural-gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

Liquidity and access to capital markets. Historically, we have accessed the debt and equity capital markets to raise money to fund growth projects, acquisitions, and to refinance long-term debt. From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute.

Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are becoming more numerous, more stringent, and more complex. These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells. In addition, in certain areas in which we operate, public protests of oil and gas operations are becoming more frequent. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets.

Impact of inflation and supply-chain disruptions. Although inflation in the United States has been relatively low in recent years, the U.S. economy currently is experiencing significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis. More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. A significant increase in inflation would raise our costs for labor, materials, and services, which could increase our operating costs and capital expenditures materially and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Overall, short- and long-term interest rates increased during 2021, but remained low relative to historical averages. Any future increases in interest rates likely will result in an increase in financing costs. Additionally, as with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics.

Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies. However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include quarterly distributions, debt service, customary operating expenses, and capital expenditures. Our sources of liquidity as of December 31, 2021, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term capital-expenditure and debt-service requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board on a quarterly basis. We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions. However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to pay distributions or to fund other short-term working capital requirements.
Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) within 55 days following each quarter’s end. Our cash flow and resulting ability to make cash distributions are dependent on our ability to generate cash flow from operations. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter. The general partner establishes cash reserves to provide for the proper conduct of our business, including (i) reserves to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. We have made cash distributions to our unitholders each quarter since our initial public offering in 2012. The Board declared a cash distribution to unitholders for the fourth quarter of 2021 of $0.32700 per unit, or $134.7 million in the aggregate. The cash distribution was paid on February 14, 2022, to our unitholders of record at the close of business on January 31, 2022.
In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. During the year ended December 31, 2021, we repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million, fulfilling the entire $250.0 million authorized program. The units were canceled immediately upon receipt.
In February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time.
For the year ended December 31, 2022, we estimate that our total capital expenditures will be between $375.0 million to $475.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).
Management continuously monitors our leverage position and coordinates our capital expenditures and quarterly distributions with expected cash inflows and projected debt-service requirements. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance maturing debt balances with longer-term debt issuances. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K.

Working capital. Working capital is an indication of liquidity and potential needs for short-term funding. Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and other capital activities. As of December 31, 2021, we had a $455.4 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Our working capital deficit was primarily due to the 4.000% Senior Notes due 2022 of $502.1 million being classified as short-term debt on the consolidated balance sheet as of December 31, 2021. As of December 31, 2021, there was $2.0 billion available for borrowing under the RCF. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures includes maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets; and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.
Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
Year Ended December 31,
thousands202120202019
Acquisitions$— $— $2,100,804 
Capital expenditures (1)
313,674 423,602 1,189,254 
Capital incurred (1)
324,150 307,644 1,055,151 
_________________________________________________________________________________________
(1)For the years ended December 31, 2021, 2020, and 2019 included $3.6 million, $4.8 million, and $23.3 million, respectively, of capitalized interest.

Acquisitions during 2019 included AMA and the 30% interest in Red Bluff Express. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Capital expenditures decreased by $109.9 million for the year ended December 31, 2021, primarily due to decreases of (i) $43.9 million at the DJ Basin complex primarily related to the completion of Latham Train II that commenced operations in the first quarter of 2020, and decreases in pipeline, well connection, and compression projects, (ii) $22.6 million at the West Texas complex primarily attributable to decreases in facility expansion, (iii) $15.7 million at the DBM oil system primarily related to the completion of the Loving ROTF Trains III and IV that commenced operations during the first and third quarters of 2020, respectively, and decreases in pipeline and well connection projects, (iv) $10.0 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects, and (v) $4.8 million at the DJ Basin oil system primarily related to decreases in pipeline projects.
Capital expenditures decreased by $765.7 million for the year ended December 31, 2020, primarily due to decreases of (i) $362.5 million at the DJ Basin complex primarily related to the completion of Latham Trains I and II that commenced operations in November 2019 and February 2020, respectively, as well as decreases in pipeline, well connection, and compression projects, (ii) $186.8 million at the West Texas complex primarily attributable to the completion of Mentone Train II that commenced operations in March 2019 and decreases in pipeline and well connection projects, (iii) $107.5 million at the DBM oil system primarily related to the completion of the Loving ROTF Train III that commenced operations in January 2020 and decreases in pipeline and well connection projects, and (iv) $90.4 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects.

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Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities:
Year Ended December 31,
thousands202120202019
Net cash provided by (used in):
Operating activities$1,766,852 $1,637,418 $1,324,100 
Investing activities(257,538)(448,254)(3,387,853)
Financing activities(1,752,237)(844,204)2,071,573 
Net increase (decrease) in cash and cash equivalents$(242,923)$344,960 $7,820 

Operating activities. Net cash provided by operating activities increased for the year ended December 31, 2021, primarily due to (i) the impact of changes in assets and liabilities, (ii) cash paid during the year ended December 31, 2020, to settle interest-rate swaps, and (iii) lower interest expense. These increases were offset partially by (i) lower cash operating income, (ii) lower distributions from equity-investment earnings, and (iii) lower interest income. Net cash provided by operating activities increased for the year ended December 31, 2020, primarily due to (i) higher cash operating income, (ii) lower cash paid to settle interest-rate swap agreements, and (iii) higher distributions from equity-investment earnings. These increases were offset partially by higher interest expense. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Investing activities. Net cash used in investing activities for the year ended December 31, 2021, included the following:

•$313.7 million of capital expenditures, primarily related to construction, expansion, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system;

•$4.4 million of capital contributions primarily paid to Cactus II;

•$41.4 million of distributions received from equity investments in excess of cumulative earnings;

•$11.1 million of decreases to materials and supplies inventory; and

•$8.0 million related to the sale of the Bison treating facility.

Net cash used in investing activities for the year ended December 31, 2020, included the following:

•$423.6 million of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM water systems, and DBM oil system;

•$57.8 million of increases to materials and supplies inventory;

•$19.4 million of capital contributions primarily paid to Cactus II and FRP for construction activities;

•$32.2 million of distributions received from equity investments in excess of cumulative earnings; and

•$20.3 million in proceeds primarily from the sale of Fort Union.

Net cash used in investing activities for the year ended December 31, 2019, included the following:

•$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;

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•$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.

Financing activities. Net cash used in financing activities for the year ended December 31, 2021, included the following:

•$533.8 million of distributions paid to WES unitholders;

•$521.9 million to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer;

•$480.0 million of repayments of outstanding borrowings under the RCF;

•$431.1 million to redeem the total principal amount outstanding of WES Operating’s 5.375% Senior Notes due 2021;

•$217.5 million of unit repurchases;

•$21.6 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020;

•$15.0 million of distributions paid to the noncontrolling interest owner of WES Operating;

•$9.1 million of distributions paid to the noncontrolling interest owner of Chipeta;

•$6.5 million of finance lease payments;

•$480.0 million of borrowings under the RCF, which were used for general partnership purposes and to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer; and

•$8.5 million of contributions from related parties.

Net cash used in financing activities for the year ended December 31, 2020, included the following:

•$3.0 billion of repayments of outstanding borrowings under the Term loan facility;

•$600.0 million of repayments of outstanding borrowings under the RCF;

•$695.8 million of distributions paid to WES unitholders;

•$203.9 million to purchase and retire portions of WES Operating’s 5.375% Senior Notes due 2021, 4.000% Senior Notes due 2022, and Floating-Rate Senior Notes via open-market repurchases;

•$32.5 million of unit repurchases;

•$15.4 million of distributions paid to the noncontrolling interest owner of WES Operating;

•$14.2 million of finance lease payments;

•$8.6 million of distributions paid to the noncontrolling interest owner of Chipeta;

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•$3.5 billion of net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued in January 2020, which were used to repay the $3.0 billion outstanding borrowings under the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes;

•$220.0 million of borrowings under the RCF, which were used for general partnership purposes;

•$20.7 million of increases in outstanding checks due mostly to ad valorem tax payments made at the end of the year; and

•$20.0 million of a one-time cash contribution from Occidental received in January 2020, pursuant to the Services Agreement, for anticipated transition costs required to establish stand-alone human resources and information technology functions.

Net cash provided by financing activities for the year ended December 31, 2019, included the following:

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

•$1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including the funding of 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.


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Debt and credit facilities. As of December 31, 2021, the carrying value of outstanding debt was $6.9 billion and we have estimated future interest and RCF fee payments totaling $342.6 million in 2022. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating Senior Notes. In mid-January 2020, WES Operating issued the Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and the Floating-Rate Senior Notes due 2023. Including the effects of the issuance prices, underwriting discounts, and interest-rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 4.542%, 5.424%, and 6.629%, respectively, at December 31, 2021. The interest rate on the Floating-Rate Senior Notes was 1.97% at December 31, 2021. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. In August 2021 and December 2021, Standard and Poor’s (“S&P”) and Fitch Ratings, respectively, upgraded WES Operating’s long-term debt from “BB” to “BB+.” In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” As a result of these upgrades, annualized borrowing costs will decrease by $23.6 million.
During the third quarter of 2021, WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer. During the first quarter of 2021, WES Operating redeemed the total principal amount outstanding of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture. During the year ended December 31, 2021, losses of $24.9 million were recognized for the retirement of these notes.
As of December 31, 2021, the 4.000% Senior Notes due 2022 were classified as short-term debt on the consolidated balance sheet. At December 31, 2021, WES Operating was in compliance with all covenants under the relevant governing indentures.
We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open-market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors. The amounts involved may be material.

Revolving credit facility. WES Operating’s $2.0 billion senior unsecured revolving credit facility is expandable to a maximum of $2.5 billion, and matures in February 2025 for each extending lender. The non-extending lender’s commitments mature in February 2024 and represent $100.0 million out of $2.0 billion of total commitments from all lenders. As of December 31, 2021, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF. As of December 31, 2021, the interest rate on any outstanding RCF borrowings was 1.60% and the facility-fee rate was 0.25%.
The RCF bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.
The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related-party transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions. As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited. At December 31, 2021, WES Operating was in compliance with all covenants under the RCF.


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Finance lease liabilities. During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles. Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification. As a result, these leases were classified as operating leases. As of December 31, 2021, we have future finance-lease payments of $3.9 million in 2022 and a total of $1.6 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties, plant, and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2021, we expect to incur asset retirement costs of $9.9 million in 2022 and a total of $298.3 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Operating leases. We have entered into operating leases for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors. As of December 31, 2021, we have future operating-lease payments of $10.7 million in 2022 and a total of $44.9 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Pipeline commitments. In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline. As of December 31, 2021, we have estimated future minimum-volume-commitment fees of $3.7 million in 2022 and a total of $11.1 million in years thereafter.

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Credit risk. We bear credit risk through exposure to non-payment or non-performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non-payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance.
We expect our exposure to the concentrated risk of non-payment or non-performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements; the contribution agreements; or the Services Agreement.

ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below.

Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands202120202019
Net income (loss) attributable to WES$916,292 $527,012 $697,241 
Limited partner interests in WES Operating not held by WES (1)
18,765 10,830 103,364 
General and administrative expenses (2)
2,932 3,552 6,819 
Other income (expense), net(11)(17)(79)
Income taxes9 — — 
Interest expense— — 245 
Net income (loss) attributable to WES Operating$937,987 $541,377 $807,590 
_________________________________________________________________________________________
(1)Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2021, 2020, and 2019. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation 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.

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Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands202120202019
WES net cash provided by operating activities$1,766,852 $1,637,418 $1,324,100 
General and administrative expenses (1)
2,932 3,552 6,819 
Non-cash equity-based compensation expense
6,912 (7,858)(1,259)
Changes in working capital(11,315)7,556 2,383 
Other income (expense), net(11)(17)(79)
Income taxes9 — — 
Interest expense— — 245 
Debt related amortization and other items, net— — (20)
WES Operating net cash provided by operating activities$1,765,379 $1,640,651 $1,332,189 
WES net cash provided by (used in) financing activities$(1,752,237)$(844,204)$2,071,573 
Distributions to WES unitholders (2)
533,758 695,834 969,073 
Distributions to WES from WES Operating (3)
(734,034)(756,112)(1,006,163)
Increase (decrease) in outstanding checks(68)(35)— 
Unit repurchases217,465 32,535 — 
Registration expenses related to the issuance of WES common units— — 855 
WGP RCF repayments— — 28,000 
Other4,336 — — 
WES Operating net cash provided by (used in) financing activities$(1,730,780)$(871,982)$2,063,338 
_________________________________________________________________________________________
(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 in 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.

Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third-party interest in Chipeta. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders in proportion to their share of limited partner interests in WES Operating. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating LTIP. Concurrent with the Merger closing, we assumed the Western Gas Partners, LP 2017 Long-Term Incentive Plan. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.
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CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee. For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Service revenues – fee based. Certain of our midstream services contracts have minimum-volume-commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost-of-service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate based on the total expected variable consideration under the contract. The cost-of-service rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses. If management determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal. See Revenue and cost of product in Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.
Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment.
Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. The primary assumptions used to estimate undiscounted future net cash flows include long-range customer production forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.
If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to impairment expense. Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.

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Impairments of equity investments. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. Management assesses its equity investments for impairment whenever events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense.

We recognized long-lived asset and other impairments of $30.5 million (which includes an other-than-temporary impairment expense of an equity investment), $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), and $6.3 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 9—Property, Plant, and Equipment and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2021, 2020, and 2019.

Fair value. Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions, and interest-rate swaps. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

RECENT ACCOUNTING DEVELOPMENTS

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

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Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Commodity-price risk. Certain of our processing services are provided under percent-of-proceeds and keep-whole agreements. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer, and because some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.
For the year ended December 31, 2021, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts. A 10% increase or decrease in commodity prices would not have a material impact on our operating income (loss), financial condition, or cash flows for the next 12 months, excluding the effect of the below-described imbalances.
We bear a limited degree of commodity-price risk with respect to settlement of natural-gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers, and for instances where actual liquids recovery or fuel usage varies from contractually stipulated amounts. Natural-gas volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and generally reflect market-index prices. Other natural-gas volumes owed to or by us are valued at our weighted-average cost of natural gas as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the settlement timing of the imbalances. See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K.

Interest-rate risk. The Federal Open Market Committee decreased its target range for the federal funds rate twice in 2020 and there were no changes to the target range in 2021. Any future increases in the federal funds rate likely will result in an increase in short-term financing costs. As of December 31, 2021, we had (i) no outstanding borrowings under the RCF that bear interest at a rate based on LIBOR or an alternative base rate at WES Operating’s option, and (ii) the Floating-Rate Senior Notes that bear interest at a rate based on LIBOR. While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings, it would impact the fair value of the senior notes at December 31, 2021. In addition, the transition from LIBOR to the Secured Overnight Financing Rate (“SOFR”) beginning in 2023 as a result of reference rate reform is not expected to materially impact interest expense on our outstanding borrowings.
Additional variable-rate debt may be issued in the future, either under the RCF or other financing sources, including commercial bank borrowings or debt issuances.

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Item 8.  Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS











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MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s and WES Operating’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s and WES Operating’s internal control over financial reporting as of December 31, 2021. This assessment was based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our assessment using the COSO criteria, we concluded the Partnership’s and WES Operating’s internal control over financial reporting was effective as of December 31, 2021.
KPMG LLP, the Partnership’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2021.

WESTERN MIDSTREAM PARTNERS, LP
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)

February 23, 2022


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WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) and Unitholders
Western Midstream Partners, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Midstream Partners, LP and subsidiaries (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of operations, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2022 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of potential impairment indicators for long-lived assets

As discussed in Notes 1, 9, and 10 to the consolidated financial statements, the Partnership assesses property, plant, and equipment together with any associated materials and supplies inventory and intangible assets (collectively, long-lived assets) for impairment when events or changes in circumstances indicate their carrying values may not
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be recoverable. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset.

We identified the evaluation of potential impairment indicators for long-lived assets as a critical audit matter. Evaluating the Partnership’s judgments in determining whether events or changes in circumstances indicate carrying values may not be recoverable required a higher degree of subjective auditor judgment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Partnership’s long-lived asset impairment process. This included controls related to the identification and assessment of qualitative impairment indicators of long-lived assets and the underlying quantitative data used to perform the analysis. We assessed the Partnership’s identification of long-lived assets for potential impairment indicators by evaluating the Partnership’s assessment of the factors considered. Specifically, we:

•evaluated overall macro-economic conditions and commodity price trends;

•analyzed the financial results for long-lived assets to identify significant degradations in the related cash flows;

•compared the remaining useful lives of the long-lived assets to the period of time required to recover the carrying value of the assets based on current cash flows; and

•examined external information on certain of the Partnership’s customers’ drilling plans and performed sensitivity analysis to determine the impact significant declines in volumes could have on the recoverability of the related long-lived assets.



/s/ KPMG LLP

We have served as the Partnership’s auditor since 2012.

Houston, Texas
February 23, 2022

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WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) and Unitholders
Western Midstream Partners, LP:

Opinion on Internal Control Over Financial Reporting

We have audited Western Midstream Partners, LP and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of operations, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 23, 2022 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


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Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ KPMG LLP
Houston, Texas
February 23, 2022


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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands except per-unit amounts202120202019
Revenues and other
Service revenues – fee based$2,462,835 $2,584,323 $2,388,191 
Service revenues – product based122,584 48,369 70,127 
Product sales290,947 138,559 286,388 
Other789 1,341 1,468 
Total revenues and other (1)
2,877,155 2,772,592 2,746,174 
Equity income, net – related parties204,645 226,750 237,518 
Operating expenses
Cost of product322,285 188,088 444,247 
Operation and maintenance581,300 580,874 641,219 
General and administrative195,549 155,769 114,591 
Property and other taxes64,267 68,340 61,352 
Depreciation and amortization551,629 491,086 483,255 
Long-lived asset and other impairments
30,543 203,889 6,279 
Goodwill impairment— 441,017 — 
Total operating expenses (2)
1,745,573 2,129,063 1,750,943 
Gain (loss) on divestiture and other, net44 8,634 (1,406)
Operating income (loss)1,336,271 878,913 1,231,343 
Interest income – Anadarko note receivable— 11,736 16,900 
Interest expense(376,512)(380,058)(303,286)
Gain (loss) on early extinguishment of debt(24,944)11,234 — 
Other income (expense), net (3)
(623)1,025 (123,785)
Income (loss) before income taxes934,192 522,850 821,172 
Income tax expense (benefit)(9,807)5,998 13,472 
Net income (loss)943,999 516,852 807,700 
Net income (loss) attributable to noncontrolling interests27,707 (10,160)110,459 
Net income (loss) attributable to Western Midstream Partners, LP$916,292 $527,012 $697,241 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Partners, LP$916,292 $527,012 $697,241 
Pre-acquisition net (income) loss allocated to Anadarko— — (29,279)
General partner interest in net (income) loss(19,815)(11,104)(5,637)
Limited partners’ interest in net income (loss) (4)
896,477 515,908 662,325 
Net income (loss) per common unit – basic (4)
$2.18 $1.18 $1.59 
Net income (loss) per common unit – diluted (4)
$2.18 $1.18 $1.59 
Weighted-average common units outstanding – basic (4)
411,309 435,554 415,794 
Weighted-average common units outstanding – diluted (4)
412,022 435,624 415,794 
_________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.6 billion, $1.8 billion, and $1.6 billion for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 6.
(2)Total operating expenses includes related-party amounts of $86.2 million, $182.7 million, and $503.2 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 6.
(3)Other income (expense), net includes losses associated with the interest-rate swap agreements for the year ended December 31, 2019. See Note 13.
(4)See Note 5.

See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20212020
ASSETS
Current assets
Cash and cash equivalents$201,999 $444,922 
Accounts receivable, net436,513 452,880 
Other current assets46,252 45,262 
Total current assets684,764 943,064 
Property, plant, and equipment
Cost12,846,078 12,641,745 
Less accumulated depreciation4,333,171 3,931,800 
Net property, plant, and equipment8,512,907 8,709,945 
Goodwill4,783 4,783 
Other intangible assets744,742 776,409 
Equity investments1,167,187 1,224,813 
Other assets (1)
158,696 171,013 
Total assets (2)
$11,273,079 $11,830,027 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$326,061 $210,691 
Short-term debt
505,932 438,870 
Accrued ad valorem taxes44,955 41,427 
Accrued liabilities263,249 269,947 
Total current liabilities1,140,197 960,935 
Long-term liabilities
Long-term debt
6,400,616 7,415,832 
Deferred income taxes12,425 22,195 
Asset retirement obligations298,275 260,283 
Other liabilities325,806 275,570 
Total long-term liabilities
7,037,122 7,973,880 
Total liabilities (3)
8,177,319 8,934,815 
Equity and partners’ capital
Common units (402,993,919 and 413,839,863 units issued and outstanding at December 31, 2021 and 2020, respectively)
2,966,955 2,778,339 
General partner units (9,060,641 units issued and outstanding at December 31, 2021 and 2020)
(8,882)(17,208)
Total partners’ capital2,958,073 2,761,131 
Noncontrolling interests137,687 134,081 
Total equity and partners’ capital3,095,760 2,895,212 
Total liabilities, equity, and partners’ capital$11,273,079 $11,830,027 
________________________________________________________________________________________
(1)Other assets includes $9.8 million and $4.2 million of NGLs line-fill inventory as of December 31, 2021 and 2020, respectively. Other assets also includes $56.2 million and $71.9 million of materials and supplies inventory as of December 31, 2021 and 2020, respectively.
(2)Total assets includes related-party amounts of $1.4 billion and $1.6 billion as of December 31, 2021 and 2020, respectively, which includes related-party Accounts receivable, net of $180.2 million and $291.3 million as of December 31, 2021 and 2020, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $270.5 million and $164.7 million as of December 31, 2021 and 2020, respectively. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
Partners’ Capital
thousandsNet
Investment
by Anadarko		Common
Units		General Partner
Units		Noncontrolling
Interests		Total
Balance at December 31, 2018$1,388,018 $951,888 $— $2,552,777 $4,892,683 
Net income (loss)29,279 662,325 5,637 110,459 807,700 
Cumulative impact of the Merger transactions (1)
— 3,169,800 — (3,169,800)— 
Issuance of general partner units— 19,861 (19,861)— — 
Above-market component of swap agreements with Anadarko (2)
— 7,407 — — 7,407 
WES Operating equity transactions, net (3)
— (755,197)— 755,197 — 
Distributions to Chipeta noncontrolling interest owner— — — (9,663)(9,663)
Distributions to noncontrolling interest owners of WES Operating— — — (118,225)(118,225)
Distributions to Partnership unitholders— (969,073)— — (969,073)
Acquisitions from related parties (4)
(2,149,218)112,872 — 28,845 (2,007,501)
Contributions of equity-based compensation from Occidental— 13,968 — — 13,968 
Net pre-acquisition contributions from (distributions to) related parties458,819 — — — 458,819 
Net contributions from (distributions to) related parties of other assets— (90)— — (90)
Adjustments of net deferred tax liabilities273,102 (4,375)— — 268,727 
Other— 561 — (20)541 
Balance at December 31, 2019$— $3,209,947 $(14,224)$149,570 $3,345,293 
Net income (loss)— 515,908 11,104 (10,160)516,852 
Distributions to Chipeta noncontrolling interest owner— — — (8,644)(8,644)
Distributions to noncontrolling interest owner of WES Operating— — — (15,434)(15,434)
Distributions to Partnership unitholders— (681,746)(14,088)— (695,834)
Unit exchange with Occidental (2)
— (256,640)— (5,238)(261,878)
Unit repurchases (5)
— (32,535)— — (32,535)
Acquisitions from related parties— (3,987)— 3,987 — 
Contributions of equity-based compensation from Occidental— 14,604 — — 14,604 
Equity-based compensation expense— 7,857 — — 7,857 
Net contributions from (distributions to) related parties (6)
— 4,466 — 20,000 24,466 
Other— 465 — — 465 
Balance at December 31, 2020$— $2,778,339 $(17,208)$134,081 $2,895,212 
Net income (loss)— 896,477 19,815 27,707 943,999 
Distributions to Chipeta noncontrolling interest owner— — — (9,117)(9,117)
Distributions to noncontrolling interest owner of WES Operating— — — (14,984)(14,984)
Distributions to Partnership unitholders— (522,269)(11,489)— (533,758)
Unit repurchases (5)
— (217,465)— — (217,465)
Contributions of equity-based compensation from Occidental
— 10,087 — — 10,087 
Equity-based compensation expense
— 17,589 — — 17,589 
Net contributions from (distributions to) related parties— 8,533 — — 8,533 
Other— (4,336)— — (4,336)
Balance at December 31, 2021$— $2,966,955 $(8,882)$137,687 $3,095,760 
_________________________________________________________________________________________
(1)See Note 1.
(2)See Note 6.
(3)For the year ended December 31, 2019, the $755.2 million decrease to partners’ capital together with net income (loss) attributable to Western Midstream Partners, LP, totaled $(58.0) million.
(4)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.
(5)See Note 5.
(6)See December 2019 Agreements—Services, Secondment, and Employee Transfer Agreement within Note 1.


See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202120202019
Cash flows from operating activities
Net income (loss)$943,999 $516,852 $807,700 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization551,629 491,086 483,255 
Long-lived asset and other impairments
30,543 203,889 6,279 
Goodwill impairment— 441,017 — 
Non-cash equity-based compensation expense
27,676 22,462 15,494 
Deferred income taxes(9,770)3,296 7,609 
Accretion and amortization of long-term obligations, net
7,635 8,654 8,441 
Equity income, net – related parties(204,645)(226,750)(237,518)
Distributions from equity-investment earnings – related parties
213,516 246,637 234,572 
(Gain) loss on divestiture and other, net(44)(8,634)1,406 
(Gain) loss on early extinguishment of debt24,944 (11,234)— 
(Gain) loss on interest-rate swaps— — 125,334 
Cash paid to settle interest-rate swaps— (25,621)(107,685)
Other260 193 236 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net16,366 (193,688)(45,033)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net114,887 144,437 (30,866)
Change in other items, net49,856 24,822 54,876 
Net cash provided by operating activities1,766,852 1,637,418 1,324,100 
Cash flows from investing activities
Capital expenditures (1)
(313,674)(423,602)(1,189,254)
Acquisitions from related parties— — (2,007,501)
Acquisitions from third parties— — (93,303)
Contributions to equity investments – related parties(4,435)(19,388)(128,393)
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
Proceeds from the sale of assets to third parties8,102 20,333 342 
(Increase) decrease in materials and supplies inventory and other11,084 (57,757)— 
Net cash used in investing activities(257,538)(448,254)(3,387,853)
Cash flows from financing activities
Borrowings, net of debt issuance costs 480,000 3,681,173 4,169,695 
Repayments of debt (1,432,966)(3,803,888)(1,467,595)
Increase (decrease) in outstanding checks(21,631)20,699 1,571 
Registration expenses related to the issuance of Partnership common units— — (855)
Distributions to Partnership unitholders (2)
(533,758)(695,834)(969,073)
Distributions to Chipeta noncontrolling interest owner(9,117)(8,644)(9,663)
Distributions to noncontrolling interest owner of WES Operating(14,984)(15,434)(118,225)
Net contributions from (distributions to) related parties8,533 24,466 458,819 
Above-market component of swap agreements with Anadarko (2)
— — 7,407 
Finance lease payments (3)
(6,513)(14,207)(508)
Unit repurchases (4)
(217,465)(32,535)— 
Other(4,336)— — 
Net cash provided by (used in) financing activities(1,752,237)(844,204)2,071,573 
Net increase (decrease) in cash and cash equivalents(242,923)344,960 7,820 
Cash and cash equivalents at beginning of period444,922 99,962 92,142 
Cash and cash equivalents at end of period$201,999 $444,922 $99,962 
Supplemental disclosures
Non-cash unit exchange with Occidental (2)
$— $(261,878)$— 
Interest paid, net of capitalized interest375,007 349,913 293,795 
Income taxes paid (reimbursements received)938 (384)96 
Accrued capital expenditures35,240 25,126 140,954 
_________________________________________________________________________________________
(1)Includes purchases from related parties of $2.0 million and $0.4 million for the years ended December 31, 2021 and 2019, respectively. See Note 6.
(2)See Note 6.
(3)For the year ended December 31, 2020, includes related-party payments of $6.4 million.
(4)Includes unit repurchases from Occidental of $50.2 million for the year ended December 31, 2021. See Note 5.
See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP):

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Midstream Operating, LP and subsidiaries (WES Operating) as of December 31, 2021 and 2020, the related consolidated statements of operations, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of WES Operating as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of WES Operating’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to WES Operating in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. WES Operating is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of WES Operating’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of potential impairment indicators for long-lived assets

As discussed in Notes 1, 9, and 10 to the consolidated financial statements, WES Operating assesses property, plant, and equipment together with any associated materials and supplies inventory and intangible assets (collectively, long-lived assets) for impairment when events or changes in circumstances indicate their carrying
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values may not be recoverable. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset.

We identified the evaluation of potential impairment indicators for long-lived assets as a critical audit matter. Evaluating WES Operating’s judgments in determining whether events or changes in circumstances indicate carrying values may not be recoverable required a higher degree of subjective auditor judgment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to WES Operating’s long-lived asset impairment process. This included controls related to the identification and assessment of qualitative impairment indicators of long-lived assets and the underlying quantitative data used to perform the analysis. We assessed WES Operating’s identification of long-lived assets for potential impairment indicators by evaluating WES Operating’s assessment of the factors considered. Specifically, we:

•evaluated overall macro-economic conditions and commodity price trends;

•analyzed the financial results for long-lived assets to identify significant degradations in the related cash flows;

•compared the remaining useful lives of the long-lived assets to the period of time required to recover the carrying value of the assets based on current cash flows; and

•examined external information on certain of WES Operating’s customers’ drilling plans and performed sensitivity analysis to determine the impact significant declines in volumes could have on the recoverability of the related long-lived assets.



/s/ KPMG LLP

We have served as WES Operating’s auditor since 2007.

Houston, Texas
February 23, 2022

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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands 202120202019
Revenues and other
Service revenues – fee based$2,462,835 $2,584,323 $2,388,191 
Service revenues – product based122,584 48,369 70,127 
Product sales290,947 138,559 286,388 
Other789 1,341 1,468 
Total revenues and other (1)
2,877,155 2,772,592 2,746,174 
Equity income, net – related parties204,645 226,750 237,518 
Operating expenses
Cost of product322,285 188,088 444,247 
Operation and maintenance581,300 580,874 641,219 
General and administrative192,617 152,217 107,772 
Property and other taxes64,267 68,340 61,352 
Depreciation and amortization551,629 491,086 483,255 
Long-lived asset and other impairments
30,543 203,889 6,279 
Goodwill impairment— 441,017 — 
Total operating expenses (2)
1,742,641 2,125,511 1,744,124 
Gain (loss) on divestiture and other, net44 8,634 (1,406)
Operating income (loss)1,339,203 882,465 1,238,162 
Interest income – Anadarko note receivable— 11,736 16,900 
Interest expense(376,512)(380,058)(303,041)
Gain (loss) on early extinguishment of debt(24,944)11,234 — 
Other income (expense), net (3)
(634)1,008 (123,864)
Income (loss) before income taxes937,113 526,385 828,157 
Income tax expense (benefit)(9,816)5,998 13,472 
Net income (loss)946,929 520,387 814,685 
Net income (loss) attributable to noncontrolling interest8,942 (20,990)7,095 
Net income (loss) attributable to Western Midstream Operating, LP$937,987 $541,377 $807,590 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Operating, LP$937,987 $541,377 $807,590 
Pre-acquisition net (income) loss allocated to Anadarko— — (29,279)
Limited partners’ interest in net income (loss)937,987 541,377 778,311 
________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.6 billion, $1.8 billion, and $1.6 billion for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 6.
(2)Total operating expenses includes related-party amounts of $89.0 million, $184.0 million, and $501.4 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 6.
(3)Other income (expense), net includes losses associated with the interest-rate swap agreements for the year ended December 31, 2019. See Note 13.

See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20212020
ASSETS
Current assets
Cash and cash equivalents$195,598 $418,537 
Accounts receivable, net436,513 407,549 
Other current assets44,421 43,244 
Total current assets676,532 869,330 
Property, plant, and equipment
Cost12,846,078 12,641,745 
Less accumulated depreciation4,333,171 3,931,800 
Net property, plant, and equipment8,512,907 8,709,945 
Goodwill4,783 4,783 
Other intangible assets744,742 776,409 
Equity investments1,167,187 1,224,813 
Other assets (1)
158,696 171,013 
Total assets (2)
$11,264,847 $11,756,293 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$374,443 $210,532 
Short-term debt
505,932 438,870 
Accrued ad valorem taxes44,955 41,427 
Accrued liabilities210,693 230,833 
Total current liabilities1,136,023 921,662 
Long-term liabilities
Long-term debt
6,400,616 7,415,832 
Deferred income taxes12,425 22,195 
Asset retirement obligations298,275 260,283 
Other liabilities324,842 275,570 
Total long-term liabilities
7,036,158 7,973,880 
Total liabilities (3)
8,172,181 8,895,542 
Equity and partners’ capital
Common units (318,675,578 units issued and outstanding at December 31, 2021 and 2020)
3,063,289 2,831,199 
Total partners’ capital3,063,289 2,831,199 
Noncontrolling interest29,377 29,552 
Total equity and partners’ capital3,092,666 2,860,751 
Total liabilities, equity, and partners’ capital$11,264,847 $11,756,293 
_________________________________________________________________________________________
(1)Other assets includes $9.8 million and $4.2 million of NGLs line-fill inventory as of December 31, 2021 and 2020, respectively. Other assets also includes $56.2 million and $71.9 million of materials and supplies inventory as of December 31, 2021 and 2020, respectively.
(2)Total assets includes related-party amounts of $1.4 billion and $1.5 billion as of December 31, 2021 and 2020, respectively, which includes related-party Accounts receivable, net of $180.2 million and $246.1 million as of December 31, 2021 and 2020, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $318.7 million and $164.3 million as of December 31, 2021 and 2020, respectively. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
Partners’ Capital  
thousandsNet
Investment
by Anadarko		Common
Units		Class C
Units		General
Partner
Units		Noncontrolling
Interest		Total
Balance at December 31, 2018$1,388,018 $2,475,540 $791,410 $206,862 $57,767 $4,919,597 
Net income (loss)29,279 765,678 10,636 1,997 7,095 814,685 
Cumulative impact of the Merger transactions (1)
— 926,236 (802,588)(123,648)— — 
Above-market component of swap agreements with Anadarko (2)
— 7,407 — — — 7,407 
Amortization of beneficial conversion feature of Class C units— (542)542 — — — 
Distributions to Chipeta noncontrolling interest owner— — — — (9,663)(9,663)
Distributions to WES Operating unitholders— (1,039,158)— (85,230)— (1,124,388)
Acquisitions from related parties (3)
(2,149,218)141,717 — — — (2,007,501)
Contributions of equity-based compensation from Occidental— 13,938 — 19 — 13,957 
Net pre-acquisition contributions from (distributions to) related parties458,819 — — — — 458,819 
Net contributions from (distributions to) related parties of other assets— (90)— — — (90)
Adjustments of net deferred tax liabilities273,102 (4,375)— — — 268,727 
Other— 269 — — — 269 
Balance at December 31, 2019$— $3,286,620 $— $— $55,199 $3,341,819 
Net income (loss)— 541,377 — — (20,990)520,387 
Distributions to Chipeta noncontrolling interest owner— — — — (8,644)(8,644)
Distributions to WES Operating unitholders— (771,546)— — — (771,546)
Acquisitions from related parties— (3,987)— — 3,987 — 
Contributions of equity-based compensation from Occidental— 14,604 — — — 14,604 
Unit exchange with Occidental (4)
— (261,878)— — — (261,878)
Net contributions from (distributions to) related parties (5)
— 24,466 — — — 24,466 
Other— 1,543 — — — 1,543 
Balance at December 31, 2020$— $2,831,199 $— $— $29,552 $2,860,751 
Net income (loss)— 937,987 — — 8,942 946,929 
Distributions to Chipeta noncontrolling interest owner— — — — (9,117)(9,117)
Distributions to WES Operating unitholders— (749,018)— — — (749,018)
Contributions of equity-based compensation from Occidental
— 10,087 — — — 10,087 
Contributions of equity-based compensation from WES
— 24,501 — — — 24,501 
Net contributions from (distributions to) related parties— 8,533 — — — 8,533 
Balance at December 31, 2021$— $3,063,289 $— $— $29,377 $3,092,666 
_______________________________________________________________________________________
(1)See Note 1.
(2)See Note 6.
(3)The amount allocated to common unitholders represents a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.
(4)See Note 5.
(5)See December 2019 Agreements—Services, Secondment, and Employee Transfer Agreement within Note 1.

See accompanying Notes to Consolidated Financial Statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202120202019
Cash flows from operating activities
Net income (loss)$946,929 $520,387 $814,685 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization551,629 491,086 483,255 
Long-lived asset and other impairments
30,543 203,889 6,279 
Goodwill impairment— 441,017 — 
Non-cash equity-based compensation expense
34,588 14,604 14,235 
Deferred income taxes(9,770)3,296 7,609 
Accretion and amortization of long-term obligations, net
7,635 8,654 8,421 
Equity income, net – related parties(204,645)(226,750)(237,518)
Distributions from equity-investment earnings – related parties
213,516 246,637 234,572 
(Gain) loss on divestiture and other, net(44)(8,634)1,406 
(Gain) loss on early extinguishment of debt24,944 (11,234)— 
(Gain) loss on interest-rate swaps— — 125,334 
Cash paid to settle interest-rate swaps— (25,621)(107,685)
Other260 193 236 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(28,965)(147,041)(44,939)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net150,055 105,352 (29,745)
Change in other items, net48,704 24,816 56,044 
Net cash provided by operating activities1,765,379 1,640,651 1,332,189 
Cash flows from investing activities
Capital expenditures (1)
(313,674)(423,602)(1,189,254)
Acquisitions from related parties— — (2,007,501)
Acquisitions from third parties— — (93,303)
Contributions to equity investments – related parties(4,435)(19,388)(128,393)
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
Proceeds from the sale of assets to third parties8,102 20,333 342 
(Increase) decrease in materials and supplies inventory and other11,084 (57,757)— 
Net cash used in investing activities(257,538)(448,254)(3,387,853)
Cash flows from financing activities
Borrowings, net of debt issuance costs480,000 3,681,173 4,169,695 
Repayments of debt (1,432,966)(3,803,888)(1,439,595)
Increase (decrease) in outstanding checks(21,699)20,664 1,571 
Distributions to WES Operating unitholders (2)
(749,018)(771,546)(1,124,388)
Distributions to Chipeta noncontrolling interest owner(9,117)(8,644)(9,663)
Net contributions from (distributions to) related parties8,533 24,466 458,819 
Above-market component of swap agreements with Anadarko (2)
— — 7,407 
Finance lease payments (3)
(6,513)(14,207)(508)
Net cash provided by (used in) financing activities(1,730,780)(871,982)2,063,338 
Net increase (decrease) in cash and cash equivalents(222,939)320,415 7,674 
Cash and cash equivalents at beginning of period418,537 98,122 90,448 
Cash and cash equivalents at end of period$195,598 $418,537 $98,122 
Supplemental disclosures
Non-cash unit exchange with Occidental (2)
$— $(261,878)$— 
Interest paid, net of capitalized interest375,007 349,913 293,561 
Income taxes paid (reimbursements received)938 (384)96 
Accrued capital expenditures35,240 25,126 140,954 
________________________________________________________________________________________
(1)Includes purchases from related parties of $2.0 million and $0.4 million for the years ended December 31, 2021 and 2019, respectively. See Note 6.
(2)See Note 6.
(3)For the year ended December 31, 2020, includes related-party payments of $6.4 million.
See accompanying Notes to Consolidated Financial Statements.
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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

General. Western Midstream Partners, LP is a Delaware master limited partnership formed in September 2012. Western Midstream Operating, LP (together with its subsidiaries, “WES Operating”) is a Delaware limited partnership formed in 2007 to acquire, own, develop, and operate midstream assets. Western Midstream Partners, LP owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of Western Midstream Operating GP, LLC, which holds the entire non-economic general partner interest in WES Operating.
For purposes of these consolidated financial statements, the “Partnership” refers to Western Midstream Partners, LP in its individual capacity or to Western Midstream Partners, LP and its subsidiaries, including Western Midstream Operating GP, LLC and WES Operating, as the context requires. “WES Operating GP” refers to Western Midstream Operating GP, LLC, individually as the general partner of WES Operating. The Partnership’s general partner, Western Midstream Holdings, LLC (the “general partner”), is a wholly owned subsidiary of Occidental Petroleum Corporation. “Occidental” refers to Occidental Petroleum Corporation, as the context requires, and its subsidiaries, excluding the general partner. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding Western Midstream Holdings, LLC. Anadarko became a wholly owned subsidiary of Occidental as a result of Occidental’s acquisition by merger of Anadarko on August 8, 2019. “Related parties” refers to Occidental (see Note 6), the Partnership’s investments accounted for under the equity method of accounting (see Note 7), and the Partnership and WES Operating for transactions that eliminate upon consolidation (see Note 6).
The Partnership is engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, natural-gas liquids (“NGLs”), and crude oil; and gathering and disposing of produced water. In its capacity as a natural-gas processor, the Partnership also buys and sells natural gas, NGLs, and condensate on behalf of itself and as an agent for its customers under certain contracts. As of December 31, 2021, the Partnership’s assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities37 3 — — 
Natural-gas processing plants/trains
24 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines
5 — — 1 
Crude-oil pipelines
3 1 — 4 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania.

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Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) and include the accounts of the Partnership and entities in which it holds a controlling financial interest, including WES Operating, WES Operating GP, proportionately consolidated interests, and equity investments (see table below). All significant intercompany transactions have been eliminated.
The following table outlines the ownership interests and the accounting method of consolidation used in the consolidated financial statements for entities not wholly owned:
Percentage Interest
Full consolidation
Chipeta (1)
75.00 %
Proportionate consolidation (2)
Springfield system50.10 %
Marcellus Interest systems33.75 %
Equity investments (3)
Mi Vida JV LLC (“Mi Vida”)50.00 %
Ranch Westex JV LLC (“Ranch Westex”)50.00 %
Front Range Pipeline LLC (“FRP”)33.33 %
Red Bluff Express Pipeline, LLC (“Red Bluff Express”)30.00 %
Enterprise EF78 LLC (“Mont Belvieu JV”)25.00 %
Rendezvous Gas Services, LLC (“Rendezvous”)22.00 %
Texas Express Pipeline LLC (“TEP”)20.00 %
Texas Express Gathering LLC (“TEG”)20.00 %
Whitethorn Pipeline Company LLC (“Whitethorn LLC”)20.00 %
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)20.00 %
Cactus II Pipeline LLC (“Cactus II”)15.00 %
Panola Pipeline Company, LLC (“Panola”)15.00 %
White Cliffs Pipeline, LLC (“White Cliffs”)10.00 %
_________________________________________________________________________________________
(1)The 25% third-party interest in Chipeta Processing LLC (“Chipeta”) is reflected within noncontrolling interests in the consolidated financial statements. See Noncontrolling interests 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.

The consolidated financial results of WES Operating are included in the Partnership’s consolidated financial statements. Throughout these notes to consolidated financial statements, and to the extent material, any differences between the consolidated financial results of the Partnership and WES Operating are discussed separately. The Partnership’s consolidated financial statements differ from those of WES Operating primarily as a result of (i) the presentation of noncontrolling interest ownership (see Noncontrolling interests below), (ii) the elimination of WES Operating GP’s investment in WES Operating with WES Operating GP’s underlying capital account, (iii) the general and administrative expenses incurred by the Partnership, which are separate from, and in addition to, those incurred by WES Operating, (iv) the inclusion of the impact of Partnership equity balances and Partnership distributions, (v) transactions between the Partnership and WES Operating that eliminate upon consolidation, and (vi) the senior secured revolving credit facility (“WGP RCF”) until its repayment in March 2019.


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Presentation of the Partnership’s assets. The Partnership’s assets include assets owned and ownership interests accounted for by the Partnership under the equity method of accounting, through its 98.0% partnership interest in WES Operating, as of December 31, 2021 (see Note 7). The Partnership also owns and controls the entire non-economic general partner interest in WES Operating GP, and the Partnership’s general partner is owned by Occidental.

Use of estimates. In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other reasonable methods. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Effects on the business, financial condition, and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information included herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation.

Noncontrolling interests. For periods subsequent to Merger completion (see Merger transactions below), the Partnership’s noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating. For periods prior to Merger completion, the Partnership’s noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, and (iv) the Class C units issued by WES Operating to a subsidiary of Anadarko as part of the funding for the acquisition of Delaware Basin Midstream, LLC (“DBM”).
For all periods presented, WES Operating’s noncontrolling interest in the consolidated financial statements consists of the 25% third-party interest in Chipeta. See Note 5.

December 2019 Agreements. On December 31, 2019, (i) the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into the below-described agreements with Occidental and/or certain of its subsidiaries, including Anadarko, and (ii) WES Operating entered into the below-described amendments to its debt agreements (collectively, the “December 2019 Agreements”).

•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, among other things agreed to (i) continue to provide certain administrative and operational services to the Partnership for up to a two-year transition period, and (ii) transfer certain Occidental employees to the Partnership, with the Partnership assuming 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 Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. In late March 2020, seconded employees’ employment was transferred to the Partnership. Most of the administrative and operational services previously provided by Occidental fully transitioned to the Partnership by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.
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•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. See Note 13.

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

Merger transactions. On February 28, 2019, the Partnership, WES Operating, Anadarko, and certain of their affiliates completed the transactions contemplated by the Contribution Agreement and Agreement and Plan of Merger (the “Merger Agreement”), dated November 7, 2018, pursuant to which, among other things, (i) Clarity Merger Sub, LLC, a wholly owned subsidiary of the Partnership, merged with and into WES Operating, with WES Operating continuing as the surviving entity and as a subsidiary of the Partnership (the “Merger”), and (ii) WES Operating acquired the Anadarko Midstream Assets (“AMA”). See Note 3.

Fair value. The fair-value-measurement standard defines fair value as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based on the degree to which the inputs are observable. The three input levels of the fair-value hierarchy are as follows:

Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

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In determining fair value, management uses observable market data when available, or models that incorporate observable market data. When a fair value measurement is required and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the cost, income, or market approach is used, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach uses management’s best assumptions regarding expectations of projected cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment because results are based on expected future events or conditions, such as contractual rates, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates, and other factors. The market approach uses management’s best assumptions regarding expectations of projected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and an assumed multiple of that EBITDA that a willing buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, the assumptions used reflect a market participant’s view of long-term revenues, costs, and other factors, and are consistent with assumptions used in the Partnership’s business plans and investment decisions.
Management uses relevant observable inputs available for the valuation technique employed to estimate fair value. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, goodwill and other intangibles, and the initial measurement of asset retirement obligations. Impairment analyses for long-lived assets, goodwill, and equity investments and the initial recognition of asset retirement obligations use Level-3 inputs.
The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 13.
The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents. All highly liquid investments with a maturity of three months or less when purchased are considered cash equivalents.

Credit losses. Accounts receivable represent contractual rights for services performed, with, on average, 30-day payment terms from the invoice date. Contract assets primarily relate to revenue accrued but not yet billed under cost-of-service contracts and accrued deficiency fees. Exposure to credit losses is analyzed within collective pools for all of our customers and, if necessary, individual customers may be analyzed separately if their credit quality becomes a concern. The Partnership monitors credit exposure to all customers to ensure exposures are within established credit limits.
As of December 31, 2021, there are no negative indications regarding the collectability of significant receivables and the Partnership will continue to monitor the credit quality of its customer base and assess collectability of these assets as appropriate. The allowance for expected credit losses was immaterial at December 31, 2021 and 2020.

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Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2021, imbalance receivables and payables were $25.3 million and $16.6 million, respectively. As of December 31, 2020, imbalance receivables and payables were $13.0 million and $3.3 million, respectively. Net changes in imbalance receivables and payables are reported in Cost of product in the consolidated statements of operations.

Inventory. The cost of NGLs inventory is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or net realizable value. NGLs inventory is reported in Other current assets and NGLs line-fill inventory is reported in Other assets on the consolidated balance sheets. Materials and supplies inventory is valued at weighted-average cost, reviewed periodically for obsolescence, and assessed for impairment together with any associated property, plant, and equipment and other intangible assets. Materials and supplies inventory is reported in Other assets on the consolidated balance sheets.

Property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid has been recorded as an adjustment to partners’ capital. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.
All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant, and equipment is also capitalized. The cost of repairs, replacements, and major maintenance projects that do not extend the useful life or increase the expected output of property, plant, and equipment is expensed as incurred.
Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. Subsequent events could cause a change in estimates of remaining useful lives or salvage value, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area.
Management assesses property, plant, and equipment together with any associated materials and supplies inventory and intangible assets, as described in Note 10, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to Long-lived asset and other impairments. Refer to Note 9 for a description of impairments recorded during the years ended December 31, 2021, 2020, and 2019.

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of assets under construction. Cumulative capitalized interest accrued during the year is expensed through depreciation or impairment.

Segments. The Partnership’s operations continue to be organized into a single operating segment, the assets of which gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water in the United States.
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Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated historic carrying value of midstream goodwill attributed to the Partnership’s assets previously acquired from Anadarko. The Partnership had allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. Goodwill is evaluated for impairment at the reporting unit level annually, as of October 1, or more often as facts and circumstances warrant. An initial qualitative assessment is performed to determine the likelihood of whether goodwill is impaired. If management concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying value, then no goodwill impairment is recorded and further testing is not necessary. If an assessment of qualitative factors does not result in management’s determination that the fair value of the reporting unit more likely than not exceeds its carrying value, then a quantitative assessment must be performed. If the quantitative assessment indicates that the carrying value of the reporting unit, including goodwill, exceeds its fair value, a goodwill impairment is recorded for the amount by which the reporting unit’s carrying value exceeds its fair value through a charge to Goodwill impairment. The Partnership recognized a goodwill impairment of $441.0 million during the first quarter of 2020, which reduced the carrying value of goodwill to zero for the gathering and processing reporting unit. See Note 10.

Asset retirement obligations. When tangible long-lived assets are acquired or constructed, the initial estimated asset retirement obligation liability is recognized at fair value, measured using discounted expected future cash outflows of the settlement obligation, with an associated increase in property, plant, and equipment. Over time, the discounted liability is adjusted up to its expected settlement value through accretion expense, which is reported within Depreciation and amortization in the consolidated statements of operations. Estimated asset retirement costs typically extend many years into the future, and estimation requires significant judgment. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant, and equipment, or depreciation expense if the asset is fully depreciated) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. See Note 12.

Environmental expenditures. The Partnership is subject to various environmental-remediation obligations arising from federal, state, and local laws and regulations. Losses associated with environmental obligations are accrued when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated, with the exception of environmental obligations acquired in a business combination, which are recorded at fair value at the time of acquisition. Accruals for estimated losses from environmental-remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study or when the evaluation of response options is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 16.

Revenue and cost of product. The Partnership provides gathering, processing, treating, transportation, and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation, and disposal of natural gas, NGLs, condensate, crude oil, and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same per-unit rate over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed at the completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties. Timing differences between amounts recognized in Service revenues – fee based and the amounts billed to customer are recognized as contract assets or contract liabilities, and are amortized over the related contract period. Prior to April 1, 2020, the Partnership also recognized revenue and cost of product expense from marketing services performed on behalf of its customers by Occidental. Effective April 1, 2020, changes to marketing-contract terms with Occidental terminated Occidental’s prior status as an agent of the Partnership for third-party sales and established Occidental as a customer of the Partnership. Accordingly, the Partnership no longer recognizes revenue and the equivalent cost of product expense for the marketing services performed by Occidental. See Note 6.
The Partnership also receives Service revenues – fee based from contracts that have minimum-volume-commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost-of-service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate based on the total expected variable consideration under the contract. The cost-of-service rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses. If the Partnership determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal.
Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as non-cash consideration for the services provided. Non-cash consideration for these services is valued at the time the services are provided. Revenue is also recognized in Product sales, along with the cost of product expense related to the sale, when the product received as non-cash consideration is sold to either Occidental or a third party.
The Partnership also purchases natural-gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. If the fees relate to services performed before control of the product has transferred to the Partnership, the fees are treated as Service revenues – fee based. Product sales revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Occidental or a third party.
The Partnership receives aid-in-construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid-in-construction reimbursements are reflected as a contract liability when received and are amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

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Defined-contribution plan. Beginning in the first quarter of 2020, employees of the Partnership are eligible to participate in the Western Midstream Savings Plan, a defined-contribution benefit plan maintained by the Partnership. All regular employees may participate in the plan by making elective contributions that are matched by the Partnership, subject to certain limitations. The Partnership also makes other contributions based on plan guidelines. The Partnership recognized expense related to the plan of $23.7 million and $12.5 million for the years ended December 31, 2021 and 2020, respectively.

Partnership income taxes. Deferred federal and state income taxes included in the accompanying consolidated financial statements are attributable to temporary differences between the financial statement carrying amount and tax basis of the Partnership’s investment in WES Operating. The Partnership’s accounting policy is to “look through” its investment in WES Operating for purposes of calculating deferred income tax asset and liability balances attributable to the Partnership’s interests in WES Operating. The Partnership had no material uncertain tax positions at December 31, 2021 or 2020.

WES Operating income taxes. WES Operating generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. WES Operating routinely assesses the realizability of its deferred tax assets. If WES Operating concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by recording a valuation allowance.
With respect to assets previously acquired from Anadarko, WES Operating recorded Anadarko’s historic federal and state current and deferred income taxes for the periods prior to the acquisition of such assets. For periods on and subsequent to the acquisition, WES Operating is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the acquired assets.
For periods beginning on and subsequent to the acquisition of assets from Anadarko, WES Operating made payments to Anadarko pursuant to the tax sharing agreement for its estimated share of taxes from all forms of taxation, excluding income taxes imposed by the United States, that are included in any combined or consolidated returns filed by Occidental. The aggregate difference in the basis of WES Operating’s assets for financial and tax reporting purposes cannot be readily determined as WES Operating does not have access to information about each partner’s tax attributes in WES Operating.
The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. WES Operating had no material uncertain tax positions at December 31, 2021 or 2020.

Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities, including common units and general partner units. The two-class method allocates earnings pursuant to a formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for the allocation of undistributed earnings to the general partner and limited partners and the circumstances in which such an allocation should be made. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes cash to its unitholders equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period, or any other economic or practical limitation on the ability to make a full distribution of the net income for the period. See Note 5.
Net income (loss) per common unit for WES Operating is not calculated because no publicly traded units are outstanding.

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Leases. The Partnership determines if an arrangement is a lease based on the rights and obligations conveyed at contract inception. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment.
When the Partnership is a lessee at the lease-commencement date, a lease is classified as either operating or finance, and right-of-use (“ROU”) assets and lease liabilities are recognized based on the present value of future lease payments over the lease term. As the rate implicit in the Partnership’s leases is generally not readily determinable, the Partnership discounts lease liabilities using the Partnership’s incremental borrowing rate at the commencement date. Non-lease components associated with leases that begin in 2019 or later are accounted for as part of the lease component, and prepaid lease payments are included as ROU assets. Options to extend or terminate a lease are included in the lease term when it is reasonably certain that the Partnership will exercise that option. Leases of 12 months or less are not recognized on the consolidated balance sheets. Lease cost is generally recognized on a straight-line basis over the lease term. For finance leases, interest expense is recognized over the lease term using the effective interest method. Variable lease payments are recognized when the obligation for those payments is incurred.
When the Partnership is a lessor at the lease-commencement date, a lease is classified as operating, sales-type, or direct financing. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. For operating leases, lease income is generally recognized on a straight-line basis over the lease term. Variable lease payments are recognized when the obligation for those payments is performed. The Partnership does not have sales-type or direct financing leases. For the Partnership’s gathering and processing assets, we elected the practical expedient to not separate lease and non-lease components. When the non-lease component is determined to be the predominant component, the combined components are accounted for under Revenue from Contracts with Customers (Topic 606).

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes revenue from contracts with customers:
Year Ended December 31,
thousands202120202019
Revenue from customers
Service revenues – fee based$2,283,584 $2,360,680 $2,388,191 
Service revenues – product based122,584 48,369 70,127 
Product sales290,947 138,559 287,055 
Total revenue from customers2,697,115 2,547,6082,745,373
Revenue from other than customers
Lease revenue (1)
179,251 223,643 — 
Net gains (losses) on commodity-price swap agreements— — (667)
Other789 1,341 1,468 
Total revenues and other$2,877,155 $2,772,592 $2,746,174 
_________________________________________________________________________________________
(1)Includes fixed- and variable-lease revenue from an operating and maintenance agreement entered into with Occidental. See Operating leases within Note 6.

Certain of the Partnership’s midstream services contracts have minimum-volume-commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost-of-service rate provisions. Beginning on December 31, 2020, the Partnership constrained revenue on certain cost-of-service agreements based on the status of commercial negotiations relating to a legal dispute with one of the contract counterparties. As of September 30, 2021, the Partnership determined it was no longer necessary to constrain revenue under these cost-of-service agreements. The Partnership has resolved the legal proceedings and commercial negotiations with the contract counterparties as of December 31, 2021.
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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $424.6 million and $428.2 million as of December 31, 2021 and 2020, respectively.
Contract assets primarily relate to (i) revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees and (ii) accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed. The following table summarizes activity related to contract assets from contracts with customers:
Year Ended December 31,
thousands20212020
Contract assets balance at beginning of year
$56,344 $67,357 
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period(10,380)(7,129)
Additional estimated revenues recognized120 3,877 
Cumulative catch-up adjustment for change in estimated consideration(23,527)(7,761)
Contract assets balance at end of year
$22,557 $56,344 
December 31,
thousands20212020
Other current assets$5,307 $5,338 
Other assets17,250 51,006 
Total contract assets from contracts with customers$22,557 $56,344 

Contract liabilities primarily relate to (i) aid-in-construction payments received from customers that must be recognized over the expected period of customer benefit, (ii) fixed and variable fees under cost-of-service contracts that are received from customers for which revenue recognition is deferred, and (iii) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit. The following table summarizes activity related to contract liabilities from contracts with customers:
Year Ended December 31,
thousands20212020
Contract liabilities balance at beginning of year
$266,937 $222,274 
Cash received or receivable, excluding revenues recognized during the period83,326 65,215 
Revenues recognized that were included in the contract liability balance at the beginning of the period(17,265)(13,842)
Cumulative catch-up adjustment for change in estimated consideration(19,852)(6,710)
Contract liabilities balance at end of year
$313,146 $266,937 
December 31,
thousands20212020
Accrued liabilities$27,763 $31,477 
Other liabilities285,383 235,460 
Total contract liabilities from contracts with customers$313,146 $266,937 

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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of December 31, 2021, are presented in the following table. The Partnership applies the optional exemptions in Revenue from Contracts with Customers (Topic 606) and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a portion of expected future revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and, in some cases, variable commodity prices for those volumes.
thousands
2022$1,056,001 
20231,000,687 
2024971,195 
2025889,113 
2026769,719 
Thereafter1,947,577 
Total$6,634,292 

3. ACQUISITIONS AND DIVESTITURES

Fort Union and Bison facilities. In October 2020, the Partnership (i) sold its 14.81% interest in Fort Union Gas Gathering, LLC (“Fort Union”), which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located in Northeast Wyoming, to a third party. The Partnership received combined proceeds of $27.0 million, resulting in a net gain on sale of $21.0 million related to the Fort Union interest that was recorded in the fourth quarter of 2020 as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed. The Partnership received total proceeds of $8.0 million, $7.0 million in the fourth quarter of 2020 and $1.0 million when the sale closed in the second quarter of 2021, resulting in a net gain on sale of $5.4 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

AMA acquisition. In February 2019, WES Operating acquired AMA from Anadarko, which is comprised of (i) the DJ Basin oil system and Wattenberg processing plant located in the DJ Basin; (ii) the DBM oil system, APC water systems, a 50% interest in Mi Vida, and a 50% interest in Ranch Westex, located in West Texas; (iii) the Wamsutter pipeline located in Wyoming; (iv) a 20% interest in Saddlehorn, a crude-oil and condensate pipeline that originates in Laramie County, Wyoming, and terminates in Cushing, Oklahoma; and (v) a 15% interest in Panola, an NGLs pipeline that originates in Panola County, Texas, and terminates in Mont Belvieu, Texas. AMA was acquired in exchange for aggregate consideration of $2.0 billion of cash, less the outstanding amount payable pursuant to an intercompany note (the “APCWH Note Payable”) assumed by WES Operating in connection with the transfer, and 45,760,201 WES Operating common units. These WES Operating common units, less 6,375,284 WES Operating common units retained by WGR Asset Holding Company LLC (“WGRAH”), converted into the right to receive common units of the Partnership at Merger completion.

Red Bluff Express acquisition. In January 2019, the Partnership acquired a 30% interest in Red Bluff Express, which owns a third-party-operated natural-gas pipeline connecting processing plants in Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas. The Partnership acquired its 30% interest from a third party via an initial net investment of $92.5 million, which represented a 30% share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand and the interest in Red Bluff Express is accounted for under the equity method of accounting. See Note 7.


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4. PARTNERSHIP DISTRIBUTIONS

Partnership distributions. Under its partnership agreement, the Partnership distributes all of its available cash (beyond proper reserves as defined in its partnership agreement) to unitholders of record on the applicable record date within 55 days following each quarter’s end. The Board of Directors of the general partner (the “Board”) declared the following cash distributions to the Partnership’s unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
Total Quarterly
Per-unit
Distribution		Total Quarterly
Cash Distribution		Distribution
Date
2019
March 31$0.61000 $276,324 May 2019
June 300.61800 279,959 August 2019
September 300.62000 280,880 November 2019
December 310.62200 281,786 February 2020
2020
March 31$0.31100 $140,893 May 2020
June 300.31100 140,900 August 2020
September 300.31100 132,255 November 2020
December 310.31100 131,265 February 2021
2021
March 31$0.31500 $132,969 May 2021
June 300.31900 134,662 August 2021
September 300.32300 134,862 November 2021
December 31 (1)
0.32700 134,749 February 2022
_________________________________________________________________________________________
(1)The Board declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2021 of $0.32700 per unit, or $134.7 million in aggregate. The cash distribution was paid on February 14, 2022, to unitholders of record at the close of business on January 31, 2022, including the general partner units.

Available cash. The amount of available cash (beyond proper reserves as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the general partner to provide for the proper conduct of the Partnership’s business, including (i) reserves to fund future capital expenditures; (ii) to comply with applicable laws, debt instruments, or other agreements; or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement and are intended to be repaid or refinanced within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund unitholder distributions.

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4. PARTNERSHIP DISTRIBUTIONS

WES Operating partnership distributions. WES Operating makes quarterly cash distributions to the Partnership and WGRAH, a subsidiary of Occidental, in proportion to their share of limited partner interests in WES Operating. See Note 5. WES Operating made the following cash distributions to its limited partners for the periods presented:
thousands
Quarters Ended
Total Quarterly
Cash Distribution		Distribution
Date
2019
March 31$283,271 May 2019
June 30288,083 August 2019
September 30289,676 November 2019
December 31290,314 February 2020
2020
March 31$143,404 May 2020
June 30143,404 August 2020
September 30143,404 November 2020
December 31127,470 February 2021
2021
March 31$137,030 May 2021
June 30140,217 August 2021
September 30140,217 November 2021
December 31140,217 February 2022

In addition to the distributions above, during the years ended December 31, 2021 and 2020, WES Operating made distributions of $204.1 million and $51.0 million, respectively, to the Partnership and WGRAH. The Partnership used its portion of the distribution to repurchase common units. See Note 5.

5. EQUITY AND PARTNERS’ CAPITAL

Holdings of Partnership equity. The Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “WES.” As of December 31, 2021, Occidental held 200,281,578 common units, representing a 48.6% limited partner interest in the Partnership, and through its ownership of the general partner, Occidental indirectly held 9,060,641 general partner units, representing a 2.2% general partner interest in the Partnership. The public held 202,712,341 common units, representing a 49.2% limited partner interest in the Partnership.
In March 2021, an affiliate of Occidental sold 11,500,000 of the Partnership’s common units it held through an underwritten offering, including 1,500,000 common units pursuant to the full exercise of the underwriters’ over-allotment option. The Partnership did not receive any proceeds from the public offering.
On September 11, 2020, the Partnership assigned its 98% interest in the 30-year $260.0 million note established in May 2008 between WES Operating and Anadarko (the “Anadarko note receivable”) to Anadarko, which Anadarko canceled and retired immediately upon receipt, in exchange for which Occidental caused certain of its subsidiaries to transfer an aggregate of 27,855,398 common units representing limited partner interests in the Partnership to the Partnership. The units were canceled by the Partnership immediately upon receipt. See Note 6.


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5. EQUITY AND PARTNERS’ CAPITAL

Partnership equity repurchases. In November 2020, the Board authorized the Partnership to buy back up to $250.0 million of the Partnership’s common units through December 31, 2021 (the “Purchase Program”). The common units were purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The Partnership repurchased 8,707,869 and 2,368,711 common units on the open market during the years ended December 31, 2021 and 2020, respectively, for an aggregate purchase price of $167.2 million and $32.5 million, respectively. In addition, the Partnership repurchased 2,500,000 common units from Occidental during the year ended December 31, 2021, for an aggregate purchase price of $50.2 million. The units were canceled by the Partnership immediately upon receipt. As of December 31, 2021, the entire $250.0 million authorized program had been fulfilled.

Holdings of WES Operating equity. As of December 31, 2021, (i) the Partnership, directly and indirectly through its ownership of WES Operating GP, owned a 98.0% limited partner interest and the entire non-economic general partner interest in WES Operating and (ii) Occidental, through its ownership of WGRAH, owned a 2.0% limited partner interest in WES Operating, which is reflected as a noncontrolling interest within the consolidated financial statements of the Partnership (see Note 1).

WES Operating Class C units. In November 2014, WES Operating issued 10,913,853 Class C units to APC Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM. All outstanding Class C units converted into WES Operating common units on a one-for-one basis immediately prior to the closing of the Merger (see Note 1).

Partnership’s net income (loss) per common unit. The common and general partner unitholders’ allocation of net income (loss) attributable to the Partnership was equal to their cash distributions plus their respective allocations of undistributed earnings or losses in accordance with their weighted-average ownership percentage during each period using the two-class method.
The Partnership’s basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit includes the effect of outstanding units issued under the Partnership’s long-term incentive plans. Net income (loss) attributable to assets acquired from Anadarko for periods prior to the acquisition of such assets was not allocated to the limited partners when calculating net income (loss) per common unit.
The following table provides a reconciliation between basic and diluted net income (loss) per common unit:
Year Ended December 31,
thousands except per-unit amounts202120202019
Net income (loss)
Limited partners’ interest in net income (loss)$896,477 $515,908 $662,325 
Weighted-average common units outstanding
Basic411,309 435,554 415,794 
Dilutive effect of non-vested phantom units713 70 — 
Diluted412,022 435,624 415,794 
Excluded due to anti-dilutive effect589 997 — 
Net income (loss) per common unit
Basic$2.18 $1.18 $1.59 
Diluted$2.18 $1.18 $1.59 

WES Operating’s net income (loss) per common unit. Net income (loss) per common unit for WES Operating is not calculated because it has no publicly traded units.

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6. RELATED-PARTY TRANSACTIONS

Summary of related-party transactions. The following tables summarize material related-party transactions included in the Partnership’s consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202120202019
Revenues and other
Service revenues – fee based$1,589,367 $1,740,999 $1,441,875 
Service revenues – product based11,888 8,509 7,062 
Product sales31,103 71,104 158,459 
Total revenues and other1,632,358 1,820,612 1,607,396 
Equity income, net – related parties (1)
204,645 226,750 237,518 
Operating expenses
Cost of product42,805 92,884 254,771 
Operation and maintenance27,805 49,533 146,990 
General and administrative (2)
15,613 40,295 101,485 
Total operating expenses86,223 182,712 503,246 
Gain (loss) on divestiture and other, net420 (2,870)— 
Interest income – Anadarko note receivable— 11,736 16,900 
Interest expense— (6)(1,970)
_________________________________________________________________________________________
(1)See Note 7.
(2)Includes (i) amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6) and (ii) equity-based compensation expense allocated to the Partnership by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Note 6).

Consolidated balance sheets
December 31,
thousands20212020
Assets
Accounts receivable, net$180,205 $291,253 
Other current assets12,490 5,493 
Equity investments (1)
1,167,187 1,224,813 
Other assets45,494 50,967 
Total assets1,405,376 1,572,526 
Liabilities
Accounts and imbalance payables49,242 6,664 
Accrued liabilities13,914 19,195 
Other liabilities207,365 138,796 
Total liabilities270,521 164,655 
_________________________________________________________________________________________
(1)See Note 7.

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6. RELATED-PARTY TRANSACTIONS

Consolidated statements of cash flows
Year Ended December 31,
thousands202120202019
Distributions from equity-investment earnings – related parties
$213,516 $246,637 $234,572 
Capital expenditures(2,000)— (425)
Acquisitions from related parties— — (2,007,501)
Contributions to equity investments – related parties(4,435)(19,388)(128,393)
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
APCWH Note Payable borrowings— — 11,000 
Repayment of APCWH Note Payable— — (439,595)
Distributions to Partnership unitholders (1)
(260,703)(367,861)(566,868)
Distributions to WES Operating unitholders (2)
(14,984)(15,434)(19,768)
Net contributions from (distributions to) related parties8,533 24,466 458,819 
Above-market component of swap agreements with Anadarko— — 7,407 
Finance lease payments— (6,382)(508)
Unit repurchases from Occidental (3)
(50,225)— — 
_________________________________________________________________________________________
(1)Represents distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
(2)Represents distributions paid to Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).
(3)The Partnership repurchased 2.5 million common units from Occidental during the year ended December 31, 2021 (see Note 5).

The following tables summarize material related-party transactions for WES Operating (which are included in the Partnership’s consolidated financial statements) to the extent the amounts differ from the Partnership’s consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202120202019
General and administrative (1)
$18,365 $41,609 $99,613 
_________________________________________________________________________________________
(1)Includes (i) amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6), (ii) equity-based compensation expense allocated to WES Operating by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Note 6), and (iii) an intercompany service fee between the Partnership and WES Operating.

Consolidated balance sheets
December 31,
thousands20212020
Accounts receivable, net$180,205 $246,083 
Accounts and imbalance payables (1)
97,749 6,664 
_________________________________________________________________________________________
(1)As of December 31, 2021, includes balances related to transactions between the Partnership and WES Operating.

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6. RELATED-PARTY TRANSACTIONS

Consolidated statements of cash flows
Year Ended December 31,
thousands202120202019
Distributions to WES Operating unitholders (1)
$(749,018)$(771,546)$(1,025,931)
_________________________________________________________________________________________
(1)Represents distributions paid to the Partnership and Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement. Includes distributions made from WES Operating to the Partnership during the years ended December 31, 2021 and 2020, that were used by the Partnership to repurchase common units. See Note 4 and Note 5.

Related-party revenues. Related-party revenues include amounts earned by the Partnership from services provided to Occidental and from the sale of natural gas, condensate, and NGLs to Occidental.

Gathering and processing agreements. The Partnership has significant gathering, processing, and produced-water disposal arrangements with affiliates of Occidental on most of its systems. While Occidental is the contracting counterparty of the Partnership, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on the Partnership’s facilities and infrastructure to bring their volumes to market. Natural-gas throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 36%, 41%, and 38% for the years ended December 31, 2021, 2020, and 2019, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 89%, 88%, and 84% for the years ended December 31, 2021, 2020, and 2019, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 87%, 87%, and 82% for the years ended December 31, 2021, 2020, and 2019, respectively.
The Partnership is currently involved in a dispute with Occidental regarding the calculation of the cost-of-service rates under an oil-gathering contract related to the Partnership’s DJ Basin oil-gathering system. If such dispute is resolved in a manner adverse to the Partnership, such resolution could have a negative impact on the Partnership’s financial condition and results of operations, including a reduction in rates and a non-cash charge to earnings.
In connection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to the Partnership’s Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation (“Sanchez”), now Mesquite Energy, Inc. (“Mesquite”) that allows Mesquite to process gas under such agreement. In December 2021, the Brasada gas processing agreement was assigned from Anadarko to Mesquite effective July 1, 2023. For this reason, Anadarko continues to be liable under the Brasada gas processing agreement until June 30, 2023, to the extent Mesquite does not perform. For all periods presented, Mesquite has performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.
Further, in connection with the sale of its Uinta Basin assets in 2020, Kerr McGee Oil & Gas Onshore LP, a subsidiary of Occidental, retained the deficiency payment obligations under a gas processing agreement at the Chipeta plant. This contingent payment obligation extends through the earlier of October 1, 2022, or the termination of the processing agreement.

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6. RELATED-PARTY TRANSACTIONS

Commodity purchase and sale agreements. Through December 31, 2020, the Partnership purchased and sold a significant amount of natural gas and NGLs from and to Anadarko Energy Services Company (“AESC”), a marketing affiliate of Occidental. Prior to April 1, 2020, AESC acted as an agent on behalf of either the Partnership or the Partnership’s customers for third-party sales. Where AESC sold natural gas and NGLs on the Partnership’s customers’ behalf, the Partnership recognized associated service revenues and cost of product expense for the marketing services performed by AESC. When product sales were on the Partnership’s behalf, the Partnership recognized product sales revenues based on Occidental’s sales price to the third party and recorded the associated cost of product expense associated with the marketing activities provided by AESC. Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership. Accordingly, the Partnership no longer recognizes service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC. This change has no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate the Partnership’s operations (see Key Performance Metrics under Part II, Item 7 of this Form 10-K).

Marketing Transition Services Agreement. Effective December 31, 2019, certain subsidiaries of Anadarko entered into a transition services agreement (the “Marketing Transition Services Agreement”) to provide marketing-related services to certain of the Partnership’s subsidiaries through December 31, 2020, subject to the option to extend such services for an additional six-month period. The Marketing Transition Services Agreement was terminated on December 31, 2020. While the Partnership still has some marketing agreements with affiliates of Occidental, the Partnership began marketing and selling substantially all of its natural gas and NGLs directly to third parties beginning on January 1, 2021.

Operating leases. As a result of the surface-use and salt-water disposal agreements being amended under the CUA (see Related-party commercial agreement below), these agreements are now classified as operating leases and a $30.0 million ROU asset, included in Other assets on the consolidated balance sheets, was recognized during the first quarter of 2021. The ROU asset will be amortized to Operation and maintenance expense over the remaining term of the agreements.
Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of the Partnership, the lessor, entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by the Partnership through December 31, 2021. In April 2021, the Partnership exercised its option to terminate the operating and maintenance agreement with Occidental effective December 31, 2021. See Note 14.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for field-related costs provided by related parties at certain of the Partnership’s assets. A portion of general and administrative expense is paid by Occidental, which results in related-party transactions pursuant to the reimbursement provisions of the Partnership’s and WES Operating’s agreements with Occidental. Cost of product expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and transactions with affiliates accounted for under the equity method of accounting. See Commodity purchase and sale agreements and Marketing Transition Services Agreement in the sections above. Related-party expenses do not bear a direct relationship to related-party revenues, and third-party expenses do not bear a direct relationship to third-party revenues.


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6. RELATED-PARTY TRANSACTIONS

Services Agreement. General and administrative expense includes costs incurred pursuant to the agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP, under which Occidental has performed certain centralized corporate functions for the Partnership and WES Operating (“Services Agreement”). Prior to December 31, 2019, the Partnership and WES Operating had separate omnibus agreements with Occidental that were terminated as part of the December 2019 Agreements.
Pursuant to the Services Agreement, which was amended and restated on December 31, 2019, specified employees of Occidental were seconded to WES Operating GP to provide, under the direction, supervision, and control of the general partner, (i) operating and routine maintenance service and (ii) corporate, administrative, and other services, with respect to the assets owned and operated by the Partnership. Occidental was reimbursed for the services provided by the seconded employees. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. In late March 2020, seconded employees’ employment was transferred to the Partnership. Most of the administrative and operational services previously provided by Occidental fully transitioned to the Partnership by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

Incentive Plans. General and administrative expense includes non-cash equity-based compensation expense allocated to the Partnership by Occidental for awards granted to the executive officers of the general partner and to other employees prior to their employment with the Partnership under (i) the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated, (ii) Occidental’s 2015 Long-Term Incentive Plan, and (iii) Occidental’s Phantom Share Unit Award Plan (collectively referred to as the “Incentive Plans”). General and administrative expense includes costs related to the Incentive Plans of $10.1 million, $14.6 million, and $12.9 million for the years ended December 31, 2021, 2020, and 2019, respectively. These amounts are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital. As of December 31, 2021, $2.2 million of estimated unrecognized compensation expense attributable to the Incentive Plans will be allocated to the Partnership over a weighted-average period of 0.5 years.

December 2019 Agreements. As discussed in more detail in Note 1, on December 31, 2019, the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into agreements with Occidental and/or certain of its subsidiaries, including Anadarko.

Merger transactions. As discussed in more detail in Note 1, on February 28, 2019, the Partnership, WES Operating, Anadarko, and certain of their affiliates completed the Merger and the other transactions contemplated in the Merger Agreement, which included the acquisition of AMA from Anadarko.

Construction reimbursement agreements and purchases from related parties. From time to time, the Partnership enters into construction reimbursement agreements with Occidental providing that the Partnership will manage the construction of certain midstream infrastructure for Occidental in the Partnership’s areas of operation. Such arrangements generally provide for a reimbursement of costs incurred by the Partnership on a cost or cost-plus basis.
Additionally, from time to time, in support of the Partnership’s business, the Partnership purchases equipment, inventory, and other miscellaneous assets, from Occidental or its affiliates. During 2019, the Partnership purchased $18.4 million of materials and supplies inventory from Occidental.

Related-party commercial agreement. During the first quarter of 2021, an affiliate of Occidental and certain wholly owned subsidiaries of the Partnership entered into a Commercial Understanding Agreement (“CUA”). Under the CUA, certain West Texas surface-use and salt-water disposal agreements were amended to reduce usage fees owed by the Partnership in exchange for the forgiveness of certain deficiency fees owed by Occidental and other unrelated contractual amendments. The present value of the reduced usage fees under the CUA was $30.0 million at the time the agreement was executed.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

Anadarko note receivable. In May 2008, WES Operating loaned $260.0 million to Anadarko in exchange for a 30-year note that bore interest at a fixed annual rate and was classified as interest income in the consolidated statements of operations. On September 11, 2020, the Partnership and Occidental entered into a Unit Redemption Agreement, pursuant to which WES Operating transferred the note receivable to Anadarko, which Anadarko immediately canceled and retired upon receipt (see Note 5).

APCWH Note Payable. In June 2017, in connection with funding the construction of the APC water systems that were acquired as part of the AMA acquisition, APC Water Holdings 1, LLC (“APCWH”) entered into an eight-year note payable agreement with Anadarko. This note payable had a maximum borrowing limit of $500.0 million, including accrued interest. The APCWH Note Payable was repaid at Merger completion (see Note 1).

Commodity-price swap agreements. WES Operating entered into commodity-price swap agreements with Anadarko to mitigate exposure to the commodity-price risk inherent in WES Operating’s percent-of-proceeds, percent-of-product, and keep-whole natural-gas processing contracts. These commodity-price swap agreements expired without renewal on December 31, 2018. For the year ended December 31, 2019, net gains (losses) on commodity-price swap agreements were $(0.7) million (due to settlement of 2018 activity in 2019) and the capital contribution from Anadarko was $7.4 million.

Customer concentration. Occidental was the only customer from which revenues exceeded 10% of consolidated revenues for all periods presented in the consolidated statements of operations.

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7. EQUITY INVESTMENTS

The following tables present the financial statement impact of the Partnership’s equity investments for the years ended December 31, 2020 and 2021:

thousandsBalance at December 31, 2019
Other-than-temporary
impairment
expense (1)
Equity
income, net		Contributions Distributions
Distributions
in excess of
cumulative
earnings (2)
DivestituresBalance at December 31, 2020
Fort Union$(610)$— $(544)$— $— $— $1,154 $— 
White Cliffs45,877 — 5,474 993 (4,892)(1,829)— 45,623 
Rendezvous32,964 — 52 — (1,994)(2,824)— 28,198 
Mont Belvieu JV103,036 — 25,913 — (25,951)(4,124)— 98,874 
TEG18,199 — 4,483 — (4,504)(1,517)— 16,661 
TEP203,556 — 36,351 — (39,655)(5,063)— 195,189 
FRP207,782 — 37,736 3,670 (39,254)(10,053)— 199,881 
Whitethorn LLC161,665 — 35,725 428 (41,070)(19)— 156,729 
Cactus II172,165 — 22,193 13,645 (31,982)(2,100)— 173,921 
Saddlehorn112,855 — 26,255 — (27,393)— — 111,717 
Panola21,783 — 2,047 — (2,047)(916)— 20,867 
Mi Vida57,807 — 10,764 — (11,563)(1,977)— 55,031 
Ranch Westex46,678 (29,399)12,127 — (9,802)(706)— 18,898 
Red Bluff Express101,960 — 8,174 652 (6,530)(1,032)— 103,224 
Total$1,285,717 $(29,399)$226,750 $19,388 $(246,637)$(32,160)$1,154 $1,224,813 

thousandsBalance at December 31, 2020
Other-than-temporary
impairment
expense (1)
Equity
income, net		ContributionsDistributions
Distributions
in excess of
cumulative
earnings (2)
Balance at December 31, 2021
White Cliffs$45,623 $— $780 $— $(199)$(5,451)$40,753 
Rendezvous28,198 — (2,155)— (1,103)(2,865)22,075 
Mont Belvieu JV98,874 — 33,991 — (33,944)(2,193)96,728 
TEG16,661 — 4,508 — (4,533)(520)16,116 
TEP195,189 — 36,547 — (36,797)(6,014)188,925 
FRP199,881 — 38,280 750 (38,275)(4,004)196,632 
Whitethorn LLC156,729 — 4,969 349 (6,428)(5,929)149,690 
Cactus II173,921 — 18,237 3,336 (18,404)(5,796)171,294 
Saddlehorn111,717 — 30,878 — (31,403)(751)110,441 
Panola20,867 — 2,188 — (2,188)(823)20,044 
Mi Vida55,031 — 10,491 — (10,596)(3,163)51,763 
Ranch Westex18,898 (11,805)12,407 — (15,657)(2,864)979 
Red Bluff Express103,224 — 13,524 — (13,989)(1,012)101,747 
Total$1,224,813 $(11,805)$204,645 $4,435 $(213,516)$(41,385)$1,167,187 
_________________________________________________________________________________________
(1)Recorded in Long-lived asset and other impairments in the consolidated statements of operations.
(2)Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual-investment basis.

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7. EQUITY INVESTMENTS

The investment balance in White Cliffs at December 31, 2021, is $4.6 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference will be accreted to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of the White Cliffs pipeline.
The investment balance in Rendezvous at December 31, 2021, includes $27.2 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of WGRI, the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and will be amortized to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of those facilities.
The investment balance in Whitethorn LLC at December 31, 2021, is $35.1 million less than the Partnership’s underlying equity in Whitethorn LLC’s net assets, primarily due to terms of the acquisition agreement which provided the Partnership a share of pre-acquisition operating cash flow. This difference will be accreted to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of Whitethorn.
The investment balance in Saddlehorn at December 31, 2021, was $18.7 million less than the Partnership’s underlying equity in Saddlehorn’s net assets, primarily due to income from an expansion project that was funded by Saddlehorn’s other owners being disproportionately allocated to the Partnership beginning in the second quarter of 2020. This difference will be accreted to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of the Saddlehorn pipeline.
The investment balance in Ranch Westex at December 31, 2021, was $36.1 million less than the Partnership’s underlying equity in Ranch Westex’s net assets. During the year ended December 31, 2021, the Partnership recognized an impairment loss of $11.8 million that resulted from a decline in value below the carrying value, which was determined to be other than temporary in nature. This investment was impaired to its estimated fair value of $2.9 million, using the income approach and Level-3 fair value inputs, due to a reduction in estimated future cash flows resulting from lower forecasted producer throughput. During the year ended December 31, 2020, the Partnership recognized an impairment loss of $29.4 million that resulted from a decline in value below the carrying value, which was determined to be other than temporary in nature.
Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss in the consolidated statements of operations.

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7. EQUITY INVESTMENTS

The following tables present the summarized combined financial information for equity investments (amounts represent 100% of investee financial information):
Year Ended December 31,
thousands202120202019
Revenues$1,808,791 $1,635,132 $1,687,116 
Operating income946,299 1,045,889 1,107,664 
Net income945,801 1,045,076 1,108,173 
December 31,
thousands20212020
Current assets$398,696 $398,933 
Property, plant, and equipment, net5,442,565 5,653,853 
Other assets182,323 171,353 
Total assets$6,023,584 $6,224,139 
Current liabilities$157,099 $144,629 
Non-current liabilities24,713 31,383 
Equity5,841,772 6,048,127 
Total liabilities and equity$6,023,584 $6,224,139 

8. INCOME TAXES

The Partnership is not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax. Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.
For the year ended December 31, 2021, the variance from the federal statutory rate was primarily impacted by a state margin rate reduction associated with Occidental’s settlement of state audit matters and our Texas margin tax liability. For the year ended December 31, 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability. For the year ended December 31, 2019, the variance from the federal statutory rate primarily was due to federal and state taxes on pre-acquisition income attributable to assets previously acquired from Anadarko, and our share of applicable Texas margin tax.
The components of income tax expense (benefit) are as follows:
 Year Ended December 31,
thousands202120202019
Current income tax expense (benefit)
Federal income tax expense (benefit)$— $— $5,550 
State income tax expense (benefit)(37)2,702 313 
Total current income tax expense (benefit)(37)2,702 5,863 
Deferred income tax expense (benefit)
Federal income tax expense (benefit)— — 2,782 
State income tax expense (benefit)(9,770)3,296 4,827 
Total deferred income tax expense (benefit)(9,770)3,296 7,609 
Total income tax expense (benefit)$(9,807)$5,998 $13,472 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. INCOME TAXES

Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows:
 Year Ended December 31,
thousands except percentages202120202019
Income (loss) before income taxes$934,192$522,850$821,172
Statutory tax rate— %— %— %
Tax computed at statutory rate$— $— $— 
Adjustments resulting from:
Federal taxes on pre-acquisition income attributable to assets acquired from Anadarko——8,332
Texas margin tax expense (benefit) (1)
(9,807)5,9985,140
Income tax expense (benefit)$(9,807)$5,998$13,472
Effective tax rate(1)%1 %2 %
_________________________________________________________________________________________
(1)Includes a tax benefit of $12.5 million for the year ended December 31, 2021, related to a reduced Texas margin tax rate resulting from Occidental’s settlement of state audit matters.

The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows:
 December 31,
thousands20212020
Depreciable property$(12,395)$(22,061)
Other intangible assets(486)(812)
Other456 678 
Net long-term deferred income tax liabilities$(12,425)$(22,195)

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9. PROPERTY, PLANT, AND EQUIPMENT

A summary of the historical cost of property, plant, and equipment is as follows:
December 31,
thousandsEstimated Useful Life20212020
LandN/A$10,955 $9,696 
Gathering systems – pipelines30 years5,386,003 5,231,212 
Gathering systems – compressors15 years2,172,953 2,096,905 
Processing complexes and treating facilities25 years3,375,317 3,424,368 
Transportation pipeline and equipment
6 to 45 years
169,356 168,205 
Produced-water disposal systems
20 years882,527 831,719 
Assets under constructionN/A98,473 176,834 
Other
3 to 40 years
750,494 702,806 
Total property, plant, and equipment12,846,078 12,641,745 
Less accumulated depreciation4,333,171 3,931,800 
Net property, plant, and equipment$8,512,907 $8,709,945 

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet placed into productive service as of the respective balance sheet date.

Long-lived asset and other impairments. During the year ended December 31, 2021, the Partnership recognized impairments of $30.5 million, primarily attributable to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of the Partnership’s investment in Ranch Westex (see Note 7).
During the year ended December 31, 2020, the Partnership recognized impairments of $203.9 million, primarily due to $150.2 million of impairments for assets located in Wyoming and Utah. These assets were impaired to estimated fair values of $112.2 million. The Partnership assesses whether events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The fair value of assets with impairment triggers were measured using the income approach and Level-3 fair value inputs. The income approach was based on the Partnership’s projected future EBITDA and free cash flows, which requires significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs. These impairments were primarily triggered by reductions in estimated future cash flows resulting from lower forecasted producer throughput and lower commodity prices. Long-lived asset and other impairments on the consolidated statements of operations also includes a $29.4 million other-than-temporary impairment for the year ended December 31, 2020, of the Partnership’s investment in Ranch Westex. The remaining impairments of $24.3 million were primarily at the DJ Basin complex and DBM oil system due to the cancellation of projects and impairments of rights-of-way.
During the year ended December 31, 2019, the Partnership recognized impairments of $6.3 million, primarily at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects.

Potential future long-lived asset impairments. As of December 31, 2021, it is reasonably possible that future commodity-price declines, prolonged depression of commodity prices, changes to producers’ drilling plans in response to lower prices, and potential producer bankruptcies could result in future long-lived asset impairments.

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10. GOODWILL AND OTHER INTANGIBLES

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Goodwill also includes the allocated historic carrying value of midstream goodwill attributed to the Partnership’s assets previously acquired from Anadarko. The Partnership’s goodwill has been allocated to two reporting units: (i) gathering and processing and (ii) transportation.
The Partnership evaluates goodwill for impairment at the reporting-unit level on an annual basis, as of October 1, or more often as facts and circumstances warrant. An initial qualitative assessment is performed to determine the likelihood of whether goodwill is impaired and if deemed necessary based on this assessment, a quantitative assessment is then performed. If the quantitative assessment indicates that the carrying value of the reporting unit, including goodwill, exceeds its fair value, a goodwill impairment is recorded for the amount by which the reporting unit’s carrying value exceeds its fair value.
During the three months ended March 31, 2020, the Partnership performed an interim goodwill impairment test due to a significant decline in the trading price of the Partnership’s common units, triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption resulting from significantly lower global demand and corresponding oversupply of crude oil. The Partnership primarily used the market approach and Level-3 inputs to estimate the fair value of its two reporting units. The market approach was based on multiples of EBITDA and the Partnership’s projected future EBITDA. The EBITDA multiples were based on current and historic multiples for comparable midstream companies of similar size and business profit to the Partnership. The EBITDA projections require significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs. The reasonableness of the market approach was tested against an income approach that was based on a discounted cash-flow analysis. Key assumptions in this analysis include the use of an appropriate discount rate, terminal-year multiples, and estimated future cash flows, including estimates of throughput, capital expenditures, and operating and general and administrative costs. The Partnership also reviewed the reasonableness of the total fair value of both reporting units to the market capitalization as of March 31, 2020, and the reasonableness of an implied acquisition premium. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the valuations. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $441.0 million during the first quarter of 2020, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero. Goodwill allocated to the transportation reporting unit of $4.8 million as of March 31, 2020, was not impaired.
The Partnership’s annual qualitative goodwill impairment assessment as of October 1, 2021, indicated no further impairment. Qualitative factors also were assessed in the fourth quarter of 2021 to review any changes in circumstances subsequent to the annual test. This assessment also indicated no impairment.

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10. GOODWILL AND OTHER INTANGIBLES

Other intangible assets. The other intangible assets balance on the consolidated balance sheets includes the fair value, net of amortization, primarily related to (i) contracts assumed in connection with processing plant acquisitions in 2011 that are part of the DJ Basin complex, which are being amortized on a straight-line basis over 38 years and (ii) contracts assumed in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years.
The Partnership assesses other intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. See Property, plant, and equipment and other intangible assets in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets.
The following table presents the gross carrying value and accumulated amortization of other intangible assets:
December 31,
thousands 20212020
Gross carrying value$979,863 $979,863 
Accumulated amortization(235,121)(203,454)
Other intangible assets$744,742 $776,409 

Amortization expense for intangible assets was $31.7 million, $33.0 million, and $32.0 million for the years ended December 31, 2021, 2020, and 2019, respectively. Intangible asset amortization to be recorded in each of the next five years is estimated to be $31.7 million per year.

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11. SELECTED COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2021202020212020
Trade receivables, net$436,513 $452,718 $436,513 $407,547 
Other receivables, net— 162 — 2 
Total accounts receivable, net$436,513 $452,880 $436,513 $407,549 

A summary of other current assets is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2021202020212020
NGLs inventory$3,370 $882 $3,370 $882 
Imbalance receivables25,309 12,976 25,309 12,976 
Prepaid insurance10,369 8,131 8,538 6,113 
Contract assets5,307 5,338 5,307 5,338 
Other1,897 17,935 1,897 17,935 
Total other current assets$46,252 $45,262 $44,421 $43,244 

A summary of accrued liabilities is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2021202020212020
Accrued interest expense$131,177 $137,307 $131,177 $137,307 
Short-term asset retirement obligations
9,934 20,215 9,934 20,215 
Short-term remediation and reclamation obligations
7,454 2,950 7,454 2,950 
Income taxes payable1,516 3,399 1,516 3,399 
Contract liabilities27,763 31,477 27,763 31,477 
Other85,405 74,599 32,849 35,485 
Total accrued liabilities$263,249 $269,947 $210,693 $230,833 



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:
 Year Ended December 31,
thousands20212020
Carrying amount of asset retirement obligations at beginning of year$280,498 $358,868 
Liabilities incurred23,923 9,565 
Liabilities settled(12,710)(20,418)
Accretion expense12,664 15,070 
Revisions in estimated liabilities3,834 (82,587)
Carrying amount of asset retirement obligations at end of year$308,209 $280,498 

Revisions in estimated liabilities for the year ended December 31, 2020, primarily related to a reduction in expected settlement costs across several of the Partnership’s assets, with the largest decreases at the Third Creek gathering system, DJ Basin complex, Hilight system, and West Texas complex.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

WES Operating is the borrower for all outstanding debt and is expected to be the borrower for all future debt issuances. The following table presents the outstanding debt:
 December 31, 2021December 31, 2020
thousandsPrincipalCarrying
Value
Fair
Value (1)
PrincipalCarrying
Value
Fair
Value (1)
Short-term debt
4.000% Senior Notes due 2022
$502,246 $502,138 $505,153 $— $— $— 
5.375% Senior Notes due 2021
— — — 431,081 430,606 436,241 
Finance lease liabilities3,794 3,794 3,794 8,264 8,264 8,264 
Total short-term debt
$506,040 $505,932 $508,947 $439,345 $438,870 $444,505 
Long-term debt
4.000% Senior Notes due 2022
$— $— $— $580,917 $580,555 $597,568 
Floating-Rate Senior Notes due 2023
213,138 212,642 213,072 239,978 238,879 235,066 
3.100% Senior Notes due 2025
732,106 728,096 764,815 1,000,000 992,900 1,028,614 
3.950% Senior Notes due 2025
399,163 395,928 418,506 500,000 494,866 512,807 
4.650% Senior Notes due 2026
474,242 471,629 516,473 500,000 496,708 524,880 
4.500% Senior Notes due 2028
400,000 396,145 437,673 400,000 395,617 415,454 
4.750% Senior Notes due 2028
400,000 396,938 444,550 400,000 396,555 418,786 
4.050% Senior Notes due 2030
1,200,000 1,190,339 1,323,595 1,200,000 1,189,407 1,342,996 
5.450% Senior Notes due 2044
600,000 593,733 717,804 600,000 593,598 607,234 
5.300% Senior Notes due 2048
700,000 687,265 844,223 700,000 687,048 694,172 
5.500% Senior Notes due 2048
350,000 342,659 418,907 350,000 342,543 343,928 
5.250% Senior Notes due 2050
1,000,000 983,709 1,183,514 1,000,000 983,512 1,100,375 
Finance lease liabilities1,533 1,533 1,533 23,644 23,644 23,644 
Total long-term debt
$6,470,182 $6,400,616 $7,284,665 $7,494,539 $7,415,832 $7,845,524 
_________________________________________________________________________________________
(1)Fair value is measured using the market approach and Level-2 fair value inputs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

Debt activity. The following table presents the debt activity for the years ended December 31, 2021and 2020:
thousandsCarrying Value
Balance at December 31, 2019$7,959,438 
RCF borrowings220,000 
Issuance of Floating-Rate Senior Notes due 2023300,000 
Issuance of 3.100% Senior Notes due 2025
1,000,000 
Issuance of 4.050% Senior Notes due 2030
1,200,000 
Issuance of 5.250% Senior Notes due 2050
1,000,000 
Finance lease liabilities24,035 
Repayments of RCF borrowings(600,000)
Repayment of Term loan facility borrowings(3,000,000)
Repayment of 5.375% Senior Notes due 2021
(68,919)
Repayment of 4.000% Senior Notes due 2022
(89,083)
Repayment of Floating-Rate Senior Notes due 2023(60,022)
Other(30,747)
Balance at December 31, 2020$7,854,702 
RCF borrowings480,000 
Repayments of RCF borrowings(480,000)
Repayment of 5.375% Senior Notes due 2021
(431,081)
Repayment of 4.000% Senior Notes due 2022
(78,671)
Repayment of Floating-Rate Senior Notes due 2023(26,840)
Repayment of 3.100% Senior Notes due 2025
(267,894)
Repayment of 3.950% Senior Notes due 2025
(100,837)
Repayment of 4.650% Senior Notes due 2026
(25,758)
Finance lease liabilities(26,582)
Other9,509 
Balance at December 31, 2021$6,906,548 

WES Operating Senior Notes. In mid-January 2020, WES Operating issued the Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 (collectively referred to as the “Fixed-Rate Senior Notes”) and the Floating-Rate Senior Notes due 2023 (the “Floating-Rate Senior Notes”). Including the effects of the issuance prices, underwriting discounts, and interest-rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 4.542%, 5.424%, and 6.629%, respectively, at December 31, 2021, and were 4.291%, 5.173%, and 6.375%, respectively, at December 31, 2020. The interest rate on the Floating-Rate Senior Notes was 1.97% and 2.07% at December 31, 2021 and 2020, respectively. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating.
During the third quarter of 2021, WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer (see Debt activity above). During the first quarter of 2021, WES Operating redeemed the total principal amount outstanding of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture. During the year ended December 31, 2021, losses of $24.9 million were recognized for the retirement of these notes. During the year ended December 31, 2020, WES Operating purchased and retired $218.0 million of certain of its senior notes and Floating-Rate Senior Notes via open-market repurchases, and gains of $13.5 million were recognized for the early retirement of these notes. Net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes were used to repay the $3.0 billion in outstanding borrowings under the Term loan facility and outstanding amounts under the RCF, and for general partnership purposes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

As of December 31, 2021, the 4.000% Senior Notes due 2022 were classified as short-term debt on the consolidated balance sheet. At December 31, 2021, WES Operating was in compliance with all covenants under the relevant governing indentures.

Revolving credit facility. WES Operating’s $2.0 billion RCF is expandable to a maximum of $2.5 billion, and matures in February 2025 for each extending lender (see Note 1). The non-extending lender’s commitments mature in February 2024 and represent $100.0 million out of $2.0 billion of total commitments from all lenders. As of December 31, 2021, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF. As of December 31, 2021 and 2020, the interest rate on any outstanding RCF borrowings was 1.60% and 1.64%, respectively. The facility-fee rate was 0.25% at December 31, 2021 and 2020.
The RCF bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.
At December 31, 2021, WES Operating was in compliance with all covenants under the RCF.

Term loan facility. In January 2020, WES Operating repaid the outstanding borrowings with proceeds from the issuance of the Fixed-Rate Senior Notes and Floating-Rate Senior Notes and terminated its $3.0 billion senior unsecured credit facility (“Term loan facility”), see WES Operating Senior Notes above. During the first quarter of 2020, a loss of $2.3 million was recognized for the early termination of the Term loan facility.

Interest-rate swaps. In December 2018 and March 2019, WES Operating entered into interest-rate swap agreements with an aggregate notional principal amount of $750.0 million and $375.0 million, respectively, to manage interest-rate risk associated with anticipated debt issuances. Pursuant to these swap agreements, WES Operating received a floating interest rate indexed to the three-month LIBOR and paid a fixed interest rate. 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 the swap agreements entered into in December 2018 and March 2019.    
In December 2019, all outstanding interest-rate swap agreements were settled. As part of the settlement, WES Operating made cash payments of $107.7 million and recorded an accrued liability of $25.6 million to be paid quarterly in 2020. For the year ended December 31, 2020, WES Operating made cash payments of $25.6 million. These cash payments were classified as cash flows from operating activities in the consolidated statements of cash flows.
The Partnership did not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swap agreements were recognized in earnings. For the year ended December 31, 2019, non-cash losses of $125.3 million were recognized, which are included in Other income (expense), net in the consolidated statements of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

Finance lease liabilities. The Partnership subleased equipment from Occidental via finance leases through April 2020. During the first quarter of 2020, the Partnership entered into finance leases with third parties for equipment and vehicles. Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification. As a result, these leases were classified as operating leases. See Note 14—Leases.

Interest expense. The following table summarizes the amounts included in interest expense:
Year Ended December 31,
thousands202120202019
Third parties
Long-term and short-term debt
$(366,570)$(369,815)$(315,872)
Finance lease liabilities(861)(1,510)— 
Commitment fees and amortization of debt-related costs(12,705)(13,501)(12,424)
Capitalized interest 3,624 4,774 26,980 
Total interest expense – third parties(376,512)(380,052)(301,316)
Related parties
APCWH Note Payable— — (1,833)
Finance lease liabilities— (6)(137)
Total interest expense – related parties— (6)(1,970)
Interest expense$(376,512)$(380,058)$(303,286)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. LEASES

The Partnership adopted ASU 2016-02, Leases (Topic 842) on January 1, 2019, using the modified retrospective method applied to all leases in existence on January 1, 2019. The Partnership elected not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases.

Lessee. The Partnership has entered into operating leases for corporate offices, shared field offices, easements, and equipment supporting the Partnership’s operations, with both Occidental and third parties as lessors. The Partnership also had subleased equipment from Occidental via finance leases that extended through April 2020.
During the first quarter of 2020, the Partnership entered into finance leases with third parties for equipment and vehicles. Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification. As a result, these leases were classified as operating leases.
The following table summarizes information related to the Partnership’s leases:
December 31,
20212020
thousands except lease term and discount rateOperating LeasesFinance LeasesOperating LeasesFinance Leases
Assets
Other assets$71,725 $— $38,985 $— 
Net property, plant, and equipment— 5,449 — 31,487 
Total lease assets (1)
$71,725 $5,449 $38,985 $31,487 
Liabilities
Accrued liabilities$10,558 $— $3,958 $— 
Short-term debt— 3,794 — 8,264 
Other liabilities35,442 — 34,843 — 
Long-term debt— 1,533 — 23,644 
Total lease liabilities (1)
$46,000 $5,327 $38,801 $31,908 
Weighted-average remaining lease term (years)8297
Weighted-average discount rate (%)4.1 3.4 5.1 4.3 
________________________________________________________________________________________
(1)For the years ended December 31, 2021 and 2020, includes additions to ROU assets of $44.9 million and $40.5 million, respectively, and additions to lease liabilities of $14.9 million and $40.5 million, respectively, related to operating leases. Includes additions to ROU assets and lease liabilities of $0.9 million and $39.7 million related to finance leases for the years ended December 31, 2021 and 2020, respectively.

The following table summarizes the Partnership’s lease cost:
Year Ended December 31,
thousands202120202019
Operating lease cost$10,753 $7,702 $6,932 
Short-term lease cost37,616 43,102 1,295 
Variable lease cost2,628 (46)256 
Sublease income(414)(414)(414)
Finance lease cost
Amortization of ROU assets7,151 8,346 562 
Interest on lease liabilities861 1,516 137 
Total lease cost$58,595 $60,206 $8,768 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. LEASES

The following table summarizes cash paid for amounts included in the measurement of lease liabilities:
Year Ended December 31,
202120202019
thousandsOperating LeasesFinance LeasesOperating LeasesFinance LeasesOperating LeasesFinance Leases
Operating cash flows$5,805 $861 $5,750 $1,516 $7,042 $118 
Financing cash flows— 6,513 — 14,207 — 508 

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities at December 31, 2021:
thousandsOperating LeasesFinance Leases
2022$10,725 $3,857 
20237,836 1,446 
20245,214 137 
20254,444 23 
20264,450 — 
Thereafter22,896 — 
Total lease payments55,565 5,463 
Less portion representing imputed interest9,565 136 
Total lease liabilities$46,000 $5,327 

Lessor. Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of the Partnership, the lessor, entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by the Partnership through December 31, 2021. The agreement and underlying contracts include (i) fixed consideration, which is measured as the minimum-volume commitment for both gathering and treating, and (ii) variable consideration, which consists of all volumes above the minimum-volume commitment. Subsequent to the initial two-year term, the agreement provides for automatic one-year extensions, unless either party exercises its option to terminate the lease with advance notice. In April 2021, the Partnership exercised its option to terminate the operating and maintenance agreement with Occidental effective December 31, 2021. For the years ended December 31, 2021 and 2020, the Partnership recognized fixed-lease revenue of $175.8 million and $175.8 million, respectively, and variable-lease revenue of $3.5 million and $47.9 million, respectively, related to these agreements, with such amounts included in Service revenues – fee based in the consolidated statements of operations.
In December 2021, one of the Partnership’s processing agreements was amended. The amended contract was determined to be a lease agreement; however, the Partnership elected the practical expedient to combine the lease and the non-lease components, which consists of processing and stabilization services, into a single service component and will account for the contract under Revenue from Contracts with Customers (Topic 606).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. EQUITY-BASED COMPENSATION

The general partner has the authority to grant equity compensation awards to its independent directors, executive officers, and employees under the (i) Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “2012 LTIP”), (ii) the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “2017 LTIP,” assumed by the Partnership in connection with the Merger), and (iii) the Western Midstream Partners, LP 2021 Long-Term Incentive Plan (the “2021 LTIP”). These plans are collectively referred to as the “WES LTIPs.” The 2012 LTIP, the 2017 LTIP, and the 2021 LTIP permit the issuance of up to 3,000,000, 3,431,251, and 9,500,000 units, respectively, of which 484,909, 2,308,578, and 9,500,000 units, respectively, remained available for future issuance as of December 31, 2021.
On March 22, 2021, the Board approved the 2021 LTIP. Subject to the capitalization adjustment provisions included in the 2021 LTIP, the total aggregate number of common units that may be delivered with respect to awards under the 2021 LTIP is 9,500,000 (the “2021 LTIP Limit”). Common units withheld from an award or surrendered by a participant to satisfy tax withholding obligations or to satisfy the payment of any exercise price with respect to an award will not be considered to be common units delivered under the 2021 LTIP for purposes of the 2021 LTIP Limit. If any award is forfeited, cancelled, exercised, settled in cash, or otherwise terminates or expires without the actual delivery of common units, the common units subject to such award will again be available for awards under the 2021 LTIP. The 2021 LTIP provides for the grant of unit options, unit appreciation rights, restricted units, phantom units, other unit-based awards, cash awards, and a unit award or a substitute award to employees and directors of the Partnership and its general partner.
The Board awards phantom units (the “Awards”) to the Partnership’s executive officers under the WES LTIPs. The Awards include (i) an award of time-vested phantom units that vest ratably over a period of three years (“Time-Based Awards”), (ii) a market award that vests after a performance period of three years based on the Partnership’s relative total unitholder return as compared to a group of peer companies (“TUR Awards”), and (iii) a performance award that vests based on the Partnership’s average return on assets over a performance period of three years (“ROA Awards”). At vesting, the number of vested units for the TUR Awards and the ROA Awards will be determined in accordance with the terms of the respective award agreements that provide for payout percentages ranging from 0% to 200% based on results achieved over the applicable performance period. At vesting, the Awards generally will be settled in Partnership common units. Prior to vesting, the Awards granted in 2020 pay in-kind distributions in the form of Partnership common units. During the years ended December 31, 2021 and 2020, the Partnership issued 21,681 and 48,070 common units, respectively, as in-kind distributions under such Awards. Prior to vesting, the Time-Based Awards granted in 2021 pay cash distributions ratably. The TUR and ROA Awards granted in 2021 pay cash distributions at vesting based on actual performance.
In addition, time-vested phantom units may be awarded under the WES LTIPs to non-executive employees and independent directors of the Partnership, which vest ratably over a period of three years and one year from the grant date, respectively. Prior to vesting, the awards to non-executive employees and independent directors pay distribution equivalents in cash.
The equity-based compensation expense attributable to these awards is amortized over the vesting periods applicable to the awards using the straight-line method. Expense is recognized based on the grant-date fair value and recorded, net of actual forfeitures, as General and administrative expense in the consolidated statements of operations. The fair value of the Time-Based Awards and non-executive awards is based on the observable market price of the Partnership’s units on the grant date of the award. The fair value of the TUR Awards is determined using a Monte Carlo simulation at the grant date of the award. The fair value of the ROA awards is adjusted quarterly based on the estimated performance rating at vesting. For ROA Awards, all performance-related fair-value changes are recognized in compensation expense during the performance period. The total fair value of phantom units vested was $8.5 million, $0.5 million, and $1.2 million for the years ended December 31, 2021, 2020, and 2019, respectively, based on the market price at the vesting date. Compensation expense for the WES LTIPs was $17.6 million, $7.9 million, and $1.0 million for the years ended December 31, 2021, 2020, and 2019, respectively. As of December 31, 2021, the Partnership had $27.4 million of estimated unrecognized compensation expense attributable to the WES LTIPs that will be recognized over a weighted-average period of 1.1 years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. EQUITY-BASED COMPENSATION

The following table summarizes time-vested award activity under the WES LTIPs for the years ended December 31, 2021, 2020, and 2019:
202120202019
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$15.69 1,307,606 $— — $35.08 7,128 
Granted17.86 1,041,635 15.49 1,442,821 29.75 25,212 
Vested14.82 (497,648)9.54 (53,551)31.62 (44,572)
Forfeited16.83 (75,921)16.27 (81,664)— — 
Converted (1)
— — — — 33.46 12,232 
Non-vested units at end of year16.97 1,775,672 15.69 1,307,606 — — 
________________________________________________________________________________________
(1)At closing of the Merger, 8,020 WES Operating phantom units awarded under the 2017 LTIP converted into phantom units of the Partnership under the 2012 LTIP.

The following table summarizes TUR Awards activity under the WES LTIPs for the years ended December 31, 2021 and 2020:
20212020
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$17.79 108,481 $— — 
Granted22.77 237,720 17.79 124,067 
Forfeited21.78 (20,984)17.79 (15,586)
Non-vested units at end of year21.17 325,217 17.79 108,481 

The following table summarizes ROA Awards activity under the WES LTIPs for the years ended December 31, 2021 and 2020:
20212020
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$16.27 108,481 $— — 
Granted15.88 237,720 16.27 124,067 
Forfeited15.96 (20,984)16.27 (15,586)
Non-vested units at end of year16.01 325,217 16.27 108,481 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state, and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. As of December 31, 2021 and 2020, the consolidated balance sheets included $10.1 million and $8.2 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities, and the long-term portion of these amounts is included in Other liabilities. The majority of payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes its environmental obligations are adequate to fund remedial actions required to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the overall results of operations, cash flows, or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 11.

Litigation and legal proceedings. From time to time, the Partnership is involved in legal, tax, regulatory, and other proceedings in various forums regarding performance, contracts, and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which the final disposition could have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows.

Other commitments. The Partnership has payment obligations, or commitments, that include, among other things, a revolving credit facility, other third-party long-term debt, obligations related to the Partnership’s capital spending programs, pipeline commitments, and various operating and finance leases. The payment obligations related to the Partnership’s capital spending programs, the majority of which is expected to be paid in the next 12 months, primarily relate to construction, expansion, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system.

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Item 9.  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    None.

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of WES’s general partner and WES Operating GP (for purposes of this Item 4, “Management”) performed an evaluation of WES’s and WES Operating’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. WES’s and WES Operating’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed in the reports that are filed or submitted under the Exchange Act is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that WES’s and WES Operating’s disclosure controls and procedures were effective as of December 31, 2021.

Management’s Annual Report on Internal Control Over Financial Reporting. See Management’s Assessment of Internal Control Over Financial Reporting under Part II, Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm. See Report of Independent Registered Public Accounting Firm under Part II, Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting. There were no changes in WES’s or WES Operating’s internal control over financial reporting during the quarter ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, WES’s or WES Operating’s internal control over financial reporting.

Item 9B.  Other Information

    None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.
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PART III

Item 10.  Directors, Executive Officers, and Corporate Governance

Management of Western Midstream Partners, LP

As an MLP, we have no directors or officers. Instead, our general partner manages our operations and activities. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes duties to our unitholders as defined and described in our partnership agreement. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it. The officers of our general partner are also officers of WES Operating GP.
Our general partner’s Board has eight members, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed limited partnership, such as us, to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee. Our Board has affirmatively determined that Messrs. Kenneth F. Owen and David J. Schulte and Ms. Lisa A. Stewart are independent as described in the rules of the NYSE and the Exchange Act.

Board Leadership Structure

Occidental owns our general partner and, within the limitations of our partnership agreement and applicable SEC and NYSE rules and regulations, also exercises broad discretion in establishing the governance provisions of our general partner’s limited liability company agreement. Accordingly, our Board structure is established by Occidental.
Although our Board structure has historically separated the roles of Chairman and Chief Executive Officer (“CEO”), our general partner’s limited liability company agreement and Corporate Governance Guidelines permit the roles of Chairman and CEO to be combined. Those roles may be combined in the future.

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Directors and Executive Officers

The biography of each director below contains information regarding that person’s service as a director, business experience, director positions held currently or at any time during the last five years, and involvement in certain legal or administrative proceedings, if applicable, and the experiences, qualifications, attributes, or skills that caused our general partner and its Board to determine that the person should serve as a director of our general partner. In light of our strategic relationship with our sponsor, Occidental, our general partner considers service as an Occidental executive to be a meaningful qualification for service as a non-independent director of our general partner.
The following table sets forth certain information with respect to the directors and executive officers of our general partner as of February 17, 2022.
NameAgePosition with Western Midstream Holdings, LLC
Peter J. Bennett54Chairman of the Board
Michael P. Ure45President, Chief Executive Officer, Chief Financial Officer, and Director
Robert W. Bourne66Senior Vice President and Chief Commercial Officer
Craig W. Collins49Senior Vice President and Chief Operating Officer
Christopher B. Dial45Senior Vice President, General Counsel and Secretary
Catherine A. Green48Senior Vice President and Chief Accounting Officer
Oscar K. Brown51Director
Nicole E. Clark 52Director
Frederick A. Forthuber 58Director (effective December 17, 2021)
Kenneth F. Owen 48Director
David J. Schulte 60Director
Lisa A. Stewart 64Director

Our directors hold office until their successors are duly elected and qualified or until the earlier of their death, resignation, removal, or disqualification. Officers serve at the discretion of the Board. There are no family relationships among any of our directors or executive officers.
Peter J. Bennett
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications 

Mr. Bennett has served as a member of our Board since August 2019, as Chairman of the Board since December 2021, and as a member of the Board’s Compensation Committee since February 2022. Mr. Bennett currently serves as President, U.S. Onshore Resources and Carbon Management, Commercial Development at Occidental. In this role, Mr. Bennett is responsible for the strategic direction and capital placement for Occidental’s U.S. Onshore Resources and Carbon Management business. He also served as Senior Vice President, Permian Resources of Occidental Oil and Gas, a subsidiary of Occidental, from April 2018 to April 2020 and as President and General Manager of Permian Resources and the Rockies from April 2020 to October 2020. Mr. Bennett previously served as President and General Manager — Permian Resources, New Mexico Delaware Basin, from January 2017 to April 2018, Chief Transformation Officer from June 2016 to January 2017, Vice President, Portfolio and Optimization of Occidental Oil and Gas from February 2016 to June 2016 and, prior to that, pioneered innovative logistical and operational solutions as Vice President, Operations Portfolio and Integrated Planning of Occidental Oil and Gas from October 2015 to February 2016.
Michael P. Ure
Houston, Texas
Director since:
August 2019
Not Independent
Officer since:
August 2019
Biography/Qualifications

Mr. Ure has served as President and Chief Executive Officer of our general partner and as a member of our Board since August 2019. Prior to joining WES, Mr. Ure served as Senior Vice President, Business Development of Occidental Oil and Gas beginning in July 2017 and as Vice President, Mergers and Acquisitions of Occidental from October 2014 to July 2017. Mr. Ure held a leadership role in evaluating acquisition and divestiture opportunities including, during his tenure, accountability for Occidental’s business development activities in North and Latin America. Prior to joining Occidental, Mr. Ure served in a leadership role with Shell Exploration and Production’s Upstream Americas Business Development organization and as an investment banker in New York, London, and Houston; most recently with Goldman, Sachs & Co. During his career, Mr. Ure has worked on total closed transactions representing more than $150 billion in value.
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Robert W. Bourne
Houston, Texas
Officer since:
October 2019
Biography/Qualifications
 
Mr. Bourne has served as Senior Vice President and Chief Commercial Officer of our general partner since October 2019. Prior to joining WES, Mr. Bourne served as a member of the board of directors of Altus Midstream Company from November 2018 to August 2019. Mr. Bourne also served as a member of the board of directors and Vice President of Business Development — Marketing of Apache Corporation from April 2017 to August 2019. Prior to joining Apache Corporation, Mr. Bourne served as a consultant advising Smith Production Inc. Mr. Bourne served as Senior Vice President of Business Development at American Midstream GP LLC, the general partner of American Midstream Partners, LP from November 2014 until December 31, 2015. Mr. Bourne has more than 31 years of experience in midstream corporate business development focused on producer and end-user relations, and was one of the founding members of the executive management team for Coral Energy.
Craig W. Collins
Houston, Texas
Officer since:
August 2019
Biography/Qualifications

Mr. Collins has served as Senior Vice President and Chief Operating Officer of our general partner since August 2019. Mr. Collins served as Vice President, Midstream of Occidental from June 2019 through December 2019. In that role, Mr. Collins was responsible for leading Occidental’s midstream operations business unit. From April 2019 to May 2019, Mr. Collins served as Chief Operating Officer of Altus Midstream. From April 2018 to April 2019, Mr. Collins served as Vice President — Midstream, of Alta Mesa Resources, Inc., which filed a petition under the federal bankruptcy laws in September 2019. Concurrent with the role at Alta Mesa Resources, Inc., Mr. Collins also served as Chief Operating Officer of Kingfisher Midstream, a wholly owned subsidiary of Alta Mesa Resources, Inc. From February 2017 to April 2018, Mr. Collins served as Senior Vice President and Chief Operating Officer of the general partner and the general partner of Western Gas Partners, LP (now WES Operating) (“Western Gas”). Mr. Collins previously served as Director of Midstream Engineering for Anadarko from July 2016 to February 2017, during which time he was responsible for the engineering and construction of midstream infrastructure for Anadarko and Western Gas. Mr. Collins joined Anadarko in 2003 and served in several roles of increasing responsibility in Anadarko’s Treasury, Corporate Development, and Midstream groups.
Christopher B. Dial
Houston, Texas
Officer since:
December 2019
Biography/Qualifications
 
Mr. Dial has served as Senior Vice President, General Counsel and Secretary of our general partner since December 2019. Prior to joining WES, Mr. Dial served as Senior Vice President, General Counsel, and Chief Compliance Officer of the general partner of American Midstream Partners, LP from January 2018 to September 2019. Prior to joining American Midstream Partners, LP, Mr. Dial served as General Counsel of Susser Holdings II, L.P. after spending over eight years in a number of roles, most recently as Associate General Counsel and Corporate Secretary, with both Susser Holdings Corporation and Sunoco LP. Mr. Dial began his career as an attorney for Andrews Kurth, LLP, representing clients on a variety of corporate, capital markets, and other transactional matters.
Catherine A. Green
Houston, Texas
Officer since:
October 2019
Biography/Qualifications
 
Ms. Green has served as Senior Vice President and Chief Accounting Officer of our general partner since May 2021, and as Vice President and Chief Accounting Officer of our general partner from October 2019 to May 2021. Ms. Green joined Anadarko in 2001 and has more than 25 years of accounting and audit experience. During her career at Anadarko, Ms. Green served in a variety of diverse roles throughout the Anadarko accounting and finance organization, including internal audit, technical U.S. GAAP accounting, internal controls, and most recently as Director, Expenditure Accounting. Prior to joining Anadarko, Ms. Green was an auditor with Grant Thornton LLP in the United Kingdom and Houston.
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Oscar K. Brown
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications

Mr. Brown has served as a member of our Board since August 2019, as Chairman of the Board’s ESG Committee since February 2021, and as a member of the Board’s Compensation Committee since February 2022. Mr. Brown served as Senior Vice President, Strategy, Business Development and Supply Chain of Occidental from November 2018 to March 2020. In this role, Mr. Brown was responsible for, among other things, Occidental’s global business development functions and global supply chain management. Mr. Brown previously served as Senior Vice President, Corporate Strategy and Business Development from July 2017 to November 2018. Prior to joining Occidental in 2016, Mr. Brown worked at Bank of America Merrill Lynch, where he most recently served as managing director and co-head of Americas Energy Investment Banking. Mr. Brown served as Occidental’s designated representative on the board of directors of Plains All American Pipeline’s governing entity, PAA GP Holdings LLC (NYSE: PAA and PAGP) from August 2017 to September 2019. Mr. Brown also serves on the board of Houston’s Alley Theatre, and as a member of that board’s Executive Committee.
Nicole E. Clark
Houston, Texas
Director since:
December 2020
Not Independent
Biography/Qualifications 

Ms. Clark has served as a member of our Board since December 2020, as a member of the Board’s ESG Committee since February 2021, and as a member of the Board’s Compensation Committee since February 2022. Ms. Clark presently holds the position of Vice President, Deputy General Counsel and Corporate Secretary at Occidental, having joined Occidental in 2014. Prior to joining Occidental, Ms. Clark was Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer at a private-equity backed industrial distributor to the energy and petrochemicals markets. Before that, Ms. Clark was a Corporate Partner at Vinson & Elkins LLP, where she specialized in mergers and acquisitions, securities regulation and corporate governance. She began her legal career with Wachtell, Lipton, Rosen & Katz where she was a Corporate Associate. Prior to entering the law, Ms. Clark was an auditor at Arthur Andersen LLP.
Frederick A. Forthuber
Houston, Texas
Director since:
December 2021
Not Independent
Biography/Qualifications 

Mr. Forthuber has served as a member of our Board and the Board’s ESG Committee since December 2021. He currently serves as President of Oxy Energy Services, LLC, a subsidiary of Occidental. In this role, Mr. Forthuber has global functional responsibility for midstream and marketing of crude oil, natural gas liquids, and natural gas. In addition, Mr. Forthuber has global functional responsibility for Health and Safety, and the Occidental Oil and Gas Regulatory and Land functions. Mr. Forthuber has more than 35 years of industry experience in oil and gas operations. He has held positions of increasing responsibility in engineering and project management since joining Occidental with the acquisition of Altura Energy in 2000. Most recently, he served as Vice President, Worldwide Operations for Occidental Oil and Gas Corporation. Prior to joining Occidental, Mr. Forthuber served in engineering roles for Altura Energy and Exxon.
Kenneth F. Owen
Houston, Texas
Director since:
September 2020
Independent
Biography/Qualifications
 
Mr. Owen has served as a member of our Board, Chairman of the Audit Committee, and a member of the Special Committee of the Board since September 2020. Mr. Owen also serves as Chairman, Chief Executive Officer and President of South Coast Terminals, one of the largest independent manufacturers of specialty chemicals and lubricant additives in the United States. Mr. Owen previously served as Co-founder, President and Chief Executive Officer of Moda Midstream from 2015 to 2018. Prior to Moda, Mr. Owen was at Oiltanking Partners, where he served as President and Chief Executive Officer of the general partner of Oiltanking Partners, L.P. (NYSE: OILT) and Oiltanking North America (OTNA). Mr. Owen originally joined OTNA in 2011 as Vice President and Chief Financial Officer and led the IPO of Oiltanking Partners. Before he joined Oiltanking, Mr. Owen worked in the energy investment banking groups at Citigroup Global Markets Inc. and UBS Investment Bank, where he advised on mergers and acquisitions, joint ventures, IPOs, and equity and debt transactions primarily for the midstream energy sector.
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David J. Schulte
Kansas City, Missouri
Director since:
September 2020
Independent
Biography/Qualifications
 
Mr. Schulte has served as a member of our Board, Chairman of the Special Committee, and a member of the Audit Committee of the Board since September 2020. Mr. Schulte serves as Chairman, Chief Executive Officer and President of CorEnergy Infrastructure, Inc., the first publicly traded energy infrastructure real estate investment trust. Prior to founding CorEnergy, Mr. Schulte was a co-founder and a Managing Director of Tortoise Capital Advisors where, from 2002 to 2015, he served on the investment committee and as a leader of new fund development, and as President of several NYSE listed closed-end funds. With assets under management of $16 billion when he left to lead CorEnergy, Tortoise had been a pioneer in developing funds focused on listed energy infrastructure debt and equity securities, including the first closed-end master limited partnership fund in 2004. Prior to co-founding Tortoise, Mr. Schulte had professional experience in private equity, including energy distribution companies, investment banking, and securities law. Mr. Schulte also served on the board of directors and audit committee for Elecsys Corporation from 1995 to 1999, and on the board of directors and audit committee for Inergy, L.P. from 2001 to 2005.
Lisa A. Stewart
Houston, Texas
Director since:
September 2020
Independent
Biography/Qualifications
 
Ms. Stewart has served as a member of our Board, a member of the Board’s Audit Committee and Special Committee since September 2020, and as Chairwoman of the Board’s Compensation Committee since February 2022. Ms. Stewart serves as Sheridan Production Partners Executive Chairman, a position she has held since April 2020. From the founding of Sheridan in 2006, she served as Chairman, Chief Executive Officer and Chief Investment Officer overseeing all aspects of Sheridan acquisitions and the implementation of Sheridan’s strategy. In September 2019, eight Sheridan entities for which Ms. Stewart served as an executive officer filed a Chapter 11 bankruptcy case in the Southern District of Texas. Ms. Stewart has more than 40 years of experience in the oil and gas industry in engineering and management positions. Prior to founding Sheridan, Ms. Stewart served as Executive Vice President of El Paso Corporation and President of El Paso E&P and other non-regulated businesses. Prior to her time at El Paso, Ms. Stewart spent 20 years at Apache, leaving in January 2004 as Executive Vice President with responsibility for reservoir engineering, business development, land, environmental, health and safety, and corporate purchasing. Ms. Stewart is currently the Lead Director of Coterra Energy, an NYSE listed energy company focused in the Permian, Mid-Continent and Pennsylvania, and an Independent Director of Jadestone Energy, an AIM-listed public energy company focused on Southeast Asia.

Reimbursement of Expenses of Our General Partner and Its Related Parties

Our general partner does not receive any management fee or other compensation for its management of WES. During 2019 under the WES omnibus agreement, we paid an annual general and administrative expense reimbursement of $250,000 and reimbursed Occidental for all insurance coverage expenses it incurred or payments it made on our behalf. Also during 2019, under WES Operating’s partnership agreement and WES Operating’s omnibus agreement, WES Operating reimbursed Occidental for general and administrative expenses allocated to it, as determined by Occidental in its reasonable discretion. On December 31, 2019, the WES and WES Operating omnibus agreements were terminated in connection with an amendment and restatement of the Services Agreement. Most of the administrative and operational services previously provided by Occidental fully transitioned to us by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement. Read Part III, Item 13 of this Form 10-K for additional information regarding these agreements.


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Board Committees

The Board has four standing committees: the Audit Committee, the Special Committee, the ESG Committee, and the Compensation Committee.

Audit Committee. The Audit Committee is comprised of three independent directors, Messrs. Owen (Chairman) and Schulte, and Ms. Stewart, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under the NYSE listing standards and the Exchange Act. In making the independence determination, the Board considered the requirements of the NYSE and our Code of Ethics and Business Conduct. The Audit Committee held five meetings in 2021.
Mr. Owen has been designated by the Board as the “Audit Committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Owen’s biography set forth above.
The Audit Committee assists the Board in its oversight of the integrity of the consolidated financial statements, internal control over financial reporting, and compliance with legal and regulatory requirements, and the policies and controls of WES and WES Operating. The Audit Committee has the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (iii) establish policies and procedures for the pre-approval of all audit, audit-related, non-audit, and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the Audit Committee and to our management, as necessary.

Special Committee. The Special Committee is comprised of three independent directors, Messrs. Schulte (Chairman) and Owen, and Ms. Stewart. The Special Committee reviews specific matters that the Board believes may involve conflicts of interest (including certain transactions with Occidental). The Special Committee will determine, as set forth in our partnership agreement, if the resolution of a conflict of interest submitted to it is fair and reasonable to us. The members of the Special Committee are not officers or employees of our general partner or directors, officers, or employees of its related parties, including Occidental. Our partnership agreement provides that any matters approved in good faith by the Special Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The Special Committee held seven meetings during 2021.

ESG Committee. The ESG Committee is comprised of three directors, Messrs. Brown (Chairman) and Forthuber, and Ms. Clark. The ESG Committee assists the Board in overseeing environmental, social, and governance matters, including those related to sustainability and climate change, that are relevant to the Partnership’s activities and performance, and devoting appropriate attention and effective response to stakeholder concerns regarding such matters. The ESG Committee held three meetings during 2021.

Compensation Committee. In February 2022, the Board established a compensation committee to assist the Board in evaluating, designing, and recommending to the Board for approval, compensation of our executive officers and non-employee directors. The Compensation Committee is comprised of four directors, Messes. Stewart (Chairwoman) and Clark, and Messrs. Bennett and Brown.


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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our Board, all of our independent directors meet in an executive session without management participation or participation by non-independent directors. Under our Corporate Governance Guidelines, these meetings are chaired on a rotating basis by the chairpersons of the Board’s Audit Committee and Special Committee.
The Board welcomes questions or comments about WES and its operations. Unitholders or interested parties may contact the Board, including any individual director, at BoardofDirectors@westernmidstream.com or at the following address: Name of the Director(s), c/o Secretary, Western Midstream Holdings, LLC, 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380.

Code of Ethics, Corporate Governance Guidelines, and Board Committee Charters

Our general partner has adopted a Code of Ethics and Business Conduct (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, principal accounting officer, Controller, and all other senior financial and accounting officers of our general partner. Our Code of Ethics is also applicable to all WES employees. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, we will disclose the information on our website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.
We make available free of charge, within the “Governance” section of our website at www.westernmidstream.com, and in print to any unitholder who so requests, our Code of Ethics, Corporate Governance Guidelines, Audit Committee charter, Special Committee charter, ESG Committee charter, and Compensation Committee charter. Requests for print copies may be directed to investors@westernmidstream.com or to: Investor Relations, Western Midstream Partners, LP, 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380, or telephone (832) 636-1009. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Item 11.  Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

This Compensation Discussion and Analysis (“CD&A”) describes the material elements, objectives, and principles of WES’s 2021 executive compensation program for its named executive officers (“NEOs”), recent compensation decisions, and the factors the Board considered in making those decisions. The NEOs for 2021 were:

NamePosition
Michael P. Ure President, Chief Executive Officer and Chief Financial Officer
Craig W. CollinsSenior Vice President and Chief Operating Officer
Christopher B. DialSenior Vice President, General Counsel and Secretary
Robert W. Bourne
Senior Vice President and Chief Commercial Officer
Charles G. Griffie (1)
Former Senior Vice President, Operations and Engineering
________________________________________________________________________________________
(1)Mr. Griffie left WES effective December 31, 2021.

Executive Summary

Subsequent to the Occidental Merger in 2019, WES undertook a strategic shift toward becoming a functionally-independent company based on the recognition that operating our business under a midstream-focused organizational infrastructure, with an independent management team solely dedicated to WES, would position WES to achieve long-term cost efficiencies, increase the quality, safety, and reliability of WES’s service offerings and operate more competitively, thereby promoting the creation of long-term value for WES unitholders. Our executive management team, none of whom have any remaining role or responsibilities at Anadarko or Occidental, was brought into WES between August of 2019 and year-end 2019 to execute this transition. This change in organizational structure remains a significant undertaking that continues to inform all of our compensation decisions, including pay levels, the design of short-and long-term incentive programs, the determination of WES specific metrics used in these programs, and the benefit programs we provide.

In 2021, our Board took the following key actions related to executive compensation:

•Implemented unit ownership guidelines for all of our officers;

•Reviewed and made compensation changes to our executive officer base salaries, target bonus opportunities, and long-term incentive awards;

•Reviewed our annual cash incentive program and updated the performance metrics to incorporate ESG metrics, expand on our existing safety measures, and include a free cash flow measure;

•Updated the treatment of distribution equivalent rights on our performance unit awards to provide for the accrual of distributions paid during the performance period, with the payment of such rights made in cash at the end of the performance period based on the actual performance of the underlying award, rather than our prior practice of paying distribution equivalent rights in units on a current basis;

•Approved the Western Midstream Partners, LP Executive Severance Plan and the Western Midstream Partners, LP Executive Change in Control Severance Plan; and

•Approved the Western Midstream Savings Restoration Plan.

These actions were taken in furtherance of our transition to a standalone midstream company and made to further align our executive compensation program with WES’s overall strategy, provide for the attraction and retention of executive talent, and align executive officer’s interest with those of our long-term unitholders.

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2021 Business and Performance Highlights

2021 continued to be a transformative year for WES as it implemented programs and policies to support the transition undertaken in 2020 to become a stand-alone midstream company. While executing this transition, and despite the continued challenges occasioned by a world-wide pandemic, during the 2021 fiscal year WES:

•Surpassed projected year-end exit-rate throughput for all product lines, driven by increased producer activity levels in the Delaware Basin.

•Maintained strong operational performance, with system availability above 99% for the second consecutive year.

•Generated $1.49 billion in Free Cash Flow, a more than 20% increase over 2020 and representing a roughly $1.45 billion improvement to the $36.7 million generated by the business in 2019.

•Surpassed year-end leverage ratio target of 4.0 times through the retirement of $431.1 million of Senior Notes due 2021 and the repurchase of $500 million of other Senior Notes, achieving a year-end leverage ratio of approximately 3.6 times, or 3.5 times on a net basis.

•Completed a $250 million unit repurchase program by repurchasing 11,207,869 units in 2021 for aggregate consideration of $217.5 million.

•Generated above-forecast 2021 Adjusted EBITDA, despite winter storm Uri, through continued producer outperformance in the Delaware Basis, commercial success in contracting additional third-party volumes, and sustainable cost savings.

•Increased the distribution 5-percent year over year.

•Published our second ESG report and established a board-level ESG Committee.

How We Make Compensation Decisions

Our Board has responsibility for evaluating and approving the officer and director compensation plans, policies, and programs of the Partnership. The Board uses several resources in reviewing elements of executive compensation and making compensation decisions. These decisions are not purely formulaic, and the Board exercises judgement and discretion as it deems appropriate. Although not required by the NYSE listing standards, in February 2022, we established a compensation committee to assist the Board in evaluating, designing, and recommending to the Board for approval, compensation of our executive officers and non-employee directors.

Compensation Philosophy. Our compensation programs are designed to attract, retain, and motivate our executive team to successfully manage the operations of a standalone midstream company. Specifically, our compensation programs are designed to:

•Align with unitholder interests;

•Emphasize performance-based compensation, balancing short-term and long-term results;

•Reward absolute and relative performance; and

•Provide total compensation opportunities competitive with those offered to other executives across our industry.


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Compensation Consultant. In 2021, the Board continued the engagement of Meridian Compensation Partners, LLC (Meridian) as its independent compensation consultant to provide advice on various executive compensation matters. This was the second year our Board was fully responsible for making pay decisions related to our NEOs and our second year to use an independent compensation consultant. In 2021, Meridian provided guidance on our benchmarking peer group, pay levels, pay mix, severance benefits, and overall executive compensation program design. The independent executive compensation consultant reports directly to the Board and provides no other material services to us.

Benchmarking Peers. With assistance from Meridian, the Board looked at several factors when determining an appropriate peer group of companies to use for benchmarking compensation opportunities. These factors included: similar midstream businesses of comparable size and scope, comparable executive roles and responsibilities, similar structure (largely independent strategy and governance (whether MLP or C-Corp)), and companies that are in competition for the same senior executive talent. After conducting an annual review, there were no changes made to the peer group compared to the peer group used to evaluate 2020 compensation decisions.
The Partnership’s peer group used for conducting the 2021 executive benchmarking assessment is listed below:
•Crestwood Equity Partners LP
•Magellan Midstream Partners LP
•DCP Midstream LP
•ONEOK, Inc.
•Enable Midstream Partners LP
•Plains All American Pipeline LP
•EnLink Midstream, LLC
•Targa Resources Corp.
•Equitrans Midstream Corporation
•Williams Companies, Inc.

Benchmarking Data. To assist in reviewing the design and structure of our executive compensation program, Meridian provided the Board with an independent assessment of the compensation programs and practices in our peer group. This assessment included compensation data and program design information that was obtained from the most recent public filings for each company. When reviewing benchmarking data, the Board reviewed 25th, 50th, and 75th percentile data, however, the Board does not target a specific percentile of the benchmark data, and in making officer compensation decisions, they take into account other considerations as noted below.

Role of Executive Officers in Setting Executive Compensation. The Board, after reviewing the information provided by Meridian and considering other factors described below, determines, with input from Meridian, each element of compensation for our CEO. When making determinations about each element of compensation for our other executive officers, the Board also considers recommendations from our CEO. Additionally, at the Board’s request, our executive officers may assess the design of, and make recommendations related to, our compensation and benefit programs, including recommendations related to the performance measures used in our incentive programs. The Board is under no obligation to implement these recommendations. Executive officers and others may also attend Board meetings when invited to do so, but the executive officers do not attend when their individual compensation is being discussed.

Other Considerations. In addition to the above resources, the Board considers other factors when making compensation decisions, such as individual experience, individual performance, internal pay equity, development and succession status, and other individual or organizational circumstances, including the current market and business environment. With respect to equity-based awards, the Board also considers the expense of such awards and the relative value of each element comprising the executive officers’ target total compensation opportunity.

2021 Annual Compensation Program

Our executive compensation program includes direct and indirect compensation elements. We believe that a majority of an executive officer’s total compensation opportunity should be performance-based; however, we do not have a specified formula that dictates the overall weighting of each element. Our Board has established an annual target total compensation program designed to support WES’s long-term strategic objectives and be competitive with industry practices.

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As illustrated in the charts below, a majority of our NEO targeted annual direct compensation is at-risk; 87% for our CEO and 75%, on average, for our other NEOs. Specifically, 72% of our CEO’s targeted annual direct compensation and 55%, on average, for our other NEOs’ targeted annual direct compensation is tied directly to WES’s unit performance through their annual long-term incentive awards.

Targeted Annual Direct Compensation
wes-20211231_g11.gif
The charts above are based on the following compensation elements, as discussed under Analysis of 2021 Compensation Actions: base salaries approved in 2021; 2021 target bonus opportunities; and the target value of the 2021 annual long-term incentive awards.

Direct Compensation Elements. The direct compensation elements for our 2021 annual compensation program are outlined in the table below.

ElementAwardPerformance MetricsPurpose
Base SalaryCashN/AProvides a fixed level of competitive compensation to attract and retain executive talent.
Equity-Based AwardsTime-Based Units
(50% of award)		Absolute Unit PriceTime-based Units align with absolute unit price and provide retentive value, especially in a volatile industry.
ROA Units
(25% of award)		3-Year Return on Assets (“ROA”)
Absolute Unit Price
ROA Units provide an incentive for NEOs to focus on efficiently managing the Partnership’s assets to generate earnings and provide a retentive value.
TUR Units
(25% of award)		3-Year Relative Total Unitholder Return (“TUR”)
Absolute Unit Price
TUR Units provide an effective comparison of our unit price performance against an industry peer group and provide a retentive value.
Annual Cash IncentivesCashControllable Cash Costs
System Availability
Discretionary Capital Spend
Leverage
Free Cash Flow
Safety & ESG		Provides incentives for NEOs to focus and excel in areas aligned with WES’s business objectives by providing rewards for short-term financial and operational results.

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Analysis of 2021 Compensation Actions

The following is a discussion of the specific actions taken by the Board in 2021 related to each of our direct compensation elements. Each element is reviewed annually, unless circumstances, such as a promotion, other change in responsibilities, significant corporate event or a material change in market conditions require a more frequent review.

Base Salary. In setting base salary levels for each of the NEOs, the Board considered a number of factors, including each executive’s experience, individual performance, internal pay equity, development, and other individual or organizational circumstances, including the current market and business environment.

NameSalary as of
February 23, 2020 ($)		Salary as of
February 21, 2021 ($)		% Change
Mr. Ure650,000 725,000 11.5 %
Mr. Collins455,000 475,000 4.4 %
Mr. Dial (1)
— 400,000 N/A
Mr. Bourne405,000 405,000 — %
Mr. Griffie405,000 405,000 — %
________________________________________________________________________________________
(1)Mr. Dial was not an NEO for the year 2020.


Mr. Ure’s salary increase was made to bring his salary closer in line with the median of the peer benchmark data for the chief executive officer position. The salary increase for Mr. Collins was made based on peer benchmarking data and internal compensation alignment considerations.

Equity-Based Long-term Incentive Awards. Our Board did not make changes in 2021 to the overall structure of our annual long-term incentive program that consists of a combination of time-based units and performance-based units. This use of both time-based and performance-based awards is intended to provide a combination of equity-based vehicles that are performance-based in absolute and relative terms while also encouraging retention. While the overall structure of our program did not change in 2021, we did update the treatment of distribution equivalent rights during the vesting period. The distribution equivalent rights are now paid in cash versus units and the distribution equivalent rights on performance units are now accrued and paid at the end of the performance period, based on actual performance rather than paid on a current basis. This change was made to increase the overall link of value delivered to company performance. Our equity-based long-term incentive program is designed to reward our executive officers for sustained long-term unit performance. This program represents 72% of targeted annual direct compensation for our CEO and an average of 55% for our other NEOs.

Time-Based Units. These units, reflecting 50% of the overall 2021 annual long-term incentive awards, vest annually over a three-year period, subject to the NEO’s continued service through the applicable vesting date. Upon vesting, the awards are settled in WES units. Distribution equivalent rights for time-based awards are paid in cash on a current basis during the vesting period.

Return on Asset Performance Units (“ROA Units”). The Board established ROA as a performance criterion for 25% of the 2021 annual long-term incentive awards. ROA is calculated each year during a three-year performance period as follows:

Adjusted
EBITDA		divided byAverage
Consolidated Total
Assets


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The actual number of ROA Units earned for the three-year performance period will be based on WES’s average annual ROA performance during the performance period. The following table reflects the payout scale used to determine the number of ROA Units earned. In the event performance falls between a whole percentage, the payout will be interpolated linearly.

WES 3 Year Average ROA19%18%17%16%15%14%13%12%11%
Payout as a % of Target200%175%150%125%100%75%50%25%0%

The number of ROA Units earned will be paid in the form of WES units after the end of the performance period and after the Board has certified our ROA results. Distribution equivalent rights for ROA Units made during the performance period are accrued and paid in cash at the end of the performance period based on the actual performance results of the underlying award.

Total Unit Return Performance Units (“TUR Units”). The Board established relative TUR as a performance criterion for 25% of the 2021 annual long-term incentive awards. The units vest based on our relative TUR performance over a three-year performance period, with TUR calculated as follows:

Average Closing Common Unit Price for the last 30 trading days of the performance periodminusAverage Closing Common Unit Price for the 30 trading days preceding the beginning of the performance periodplusDistributions paid per Common Unit over the performance period (based on ex-dividend date)
divided by
Average Closing Common Unit Price for the 30 trading days preceding the beginning of the performance period

The industry peer group for our 2021 TUR awards is listed below:
•Antero Midstream Corporation (1)
•Equitrans Midstream Corporation (1)
•Crestwood Equity Partners LP
•Magellan Midstream Partners LP
•DCP Midstream LP
•Plains All American Pipeline LP
•EnLink Midstream, LLC
•Targa Resources Corporation (1)
(1)These companies were added to the peer group in 2021 to replace EQM Midstream Partners LP, Enable Midstream Partners LP, and Noble Midstream Partners, all companies that at the time of grant were no longer publicly traded or had announced transactions that would cause them to no longer be publicly traded.

If during the performance period, a peer company is acquired, ceases to exist, ceases to be a publicly-traded partnership, files for bankruptcy, spins off 25% or more of its assets, or sells all or substantially all of its assets, then such partnership shall be deemed to fall to the bottom of the relative TUR ranking for the performance period.
The actual number of TUR Units earned for the three-year performance period will be based on WES’s relative TUR performance during the performance period. The following table reflects the payout scale used to determine the number of TUR Units earned.

Final Relative Ranking123456789
Payout as a % of Target200%175%150%125%100%75%50%25%0%

The number of TUR Units earned will be paid in the form of WES units after the end of the performance period and after the Board has certified our relative TUR performance. Distribution equivalent rights for TUR Units made during the performance period are accrued and paid in cash at the end of the performance period based on the actual performance of the underlying award.

2021 Equity Awards. Effective February 18, 2021, the Board approved the following annual long-term incentive awards under the Western Gas Equity Partners, LP 2017 Long-Term Incentive Plan. These awards are included in the
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Grants of Plan-Based Awards Table. The target value of the 2021 annual equity awards granted to the NEOs reflect an increase of approximately 18%, on average, compared to their prior year target value of annual awards. In determining the annual equity awards, the Board took into consideration our peer benchmarking data, internal pay equity, retention concerns, and current NEO unit ownership levels.
Total Target LTI Value ($) (1)
Time-Based Units (50%)TUR Units (25%)ROA Units (25%)
NameNumber of Units (#)Target Value ($)Number of Units (#)Target Value ($)Number of Units (#)Target Value ($)
Mr. Ure4,000,000 125,945 2,000,000 62,972 1,000,000 62,972 1,000,000 
Mr. Collins1,500,000 47,229 750,000 23,615 375,000 23,615 375,000 
Mr. Dial850,000 26,763 425,000 13,382 212,500 13,382 212,500 
Mr. Bourne700,000 22,040 350,000 11,020 175,000 11,020 175,000 
Mr. Griffie (2)
800,000 25,189 400,000 12,594 200,000 12,594 200,000 
_________________________________________________________________________________________
(1)Target LTI values approved by the Board vary from those reported in the Summary Compensation Table and Grants of Plan-Based Awards Table, which are calculated in accordance with FASB ASC Topic 718.
(2)Per the terms of Mr. Griffie’s award agreements, upon his departure from WES, he received a prorated portion of these awards.

Performance Ownership Awards. In addition to the annual awards, in February 2021, the Board approved one-time performance ownership awards to each of the NEOs. These awards were granted to increase the equity holdings of our executive officers, all who were newly appointed to WES in 2019. They were granted in the form of TUR Units and ROA Units in order to have the full value delivered directly linked to and contingent upon the Partnership’s performance.
Name
Target Value ($) (1)
Number of
TUR Units (#)		Number of
ROA Units (#)
Mr. Ure1,500,000 47,229 47,229 
Mr. Collins750,000 23,615 23,615 
Mr. Dial425,000 13,382 13,382 
Mr. Bourne350,000 11,020 11,020 
Mr. Griffie (2)
400,000 12,594 12,594 
_________________________________________________________________________________________
(1)Target LTI values approved by the Board vary from those reported in the Summary Compensation Table and Grants of Plan-Based Awards Table, which are calculated in accordance with FASB ASC Topic 718.
(2)Per the terms of Mr. Griffie’s award agreements, upon his departure from WES, he received a prorated portion of these awards.

Performance-Based Annual Cash Incentives—WES Cash Bonus Program. Our Board has approved the WES Cash Bonus Program (“WCB Program”) under our US Incentive Compensation Program. Under the WCB Program, annual cash bonus awards are earned by eligible employees, including our NEOs, taking into account the achievement of specified business objectives and individual performance objectives. The Board maintains full discretion in determining overall performance under the WCB Program and may adjust bonus payouts based on factors it deems relevant.
In February 2021, individual target bonus dollar values were approved by the Board for each of our NEOs as noted in the table below.
2020 Target Bonus2021 Target Bonus
Name$% of Salary$% of Salary
Mr. Ure650,000100%833,750115%
Mr. Collins390,00086%475,000100%
Mr. Dial (1)
——275,00069%
Mr. Bourne330,00081%330,00081%
Mr. Griffie345,00085%345,00085%
_________________________________________________________________________________________
(1)Mr. Dial was not an NEO for the year 2020.
Changes to target bonuses for 2021 were determined based on a review of our peer benchmarking data and internal pay equity considerations.

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Performance Metrics. In February 2021, the Board approved performance measures and targets to be used as an aid in determining annual cash awards under the WCB Program for the one-year performance period that ended December 31, 2021. Our annual incentive program was designed to include measures that support our primary business strategy of creating long-term value for our unitholders by safely delivering above-average customer service and system availability, and obtaining new business over time, while achieving costs efficiencies and optimizing our financial profile. The overall design of the 2021 WCB Program is similar to the 2020 WCB Program, but with adjustments to incorporate quantitative ESG metrics into the Program (Total Volumetric Spill Rate and Social Engagement) and expand our safety component to include DART in addition to TRIR. Free cash flow was also added to the 2021 WCB Program to incorporate a measure related to the cash available for the quarterly distributions to our unitholders.
The table below reflects the Partnership’s 2021 performance metrics, performance targets and performance under these metrics.
Performance MetricRelative Weighting FactorWCB Program
Performance
Targets
WCB Program Performance
Results (1)
Controllable Cash Costs25%
O&M Expense as a % of Adjusted gross
margin (16.75%) (2)
21.8%20.8%
Controllable Cash G&A (8.25%) (3)
$123MM$120.5MM
System Availability (4)
15%> 99%99.2%
Discretionary Growth Capital Spend (5)
15%< $280MM$192MM
Leverage Ratio (6)
15%3.8x 3.4x
Free cash flow (7)
15%$1,200MM$1,626.4MM
Safety & ESG15%
TRIR (9%) (8)
0.300.34
DART (3%) (9)
0.060.13
TVSR (1.5%) (10)
10.007.30
Social Engagement (1.5%) (11)
50% Employee Volunteer Participation62.2%
Participation
_________________________________________________________________________________________
(1)These performance results reflect the Board’s discretion to adjust for specific unplanned items including, but not limited to, the impact of winter storm Uri, unbudgeted growth capital spend to support unplanned producer development, the effect of COVID-related recordable incidents on our safety results, and certain other unplanned expenses.
(2)O&M Expense as a % of Adjusted gross margin performance results reflect the Board’s discretionary adjustment to exclude the impact of winter storm Uri and certain other unplanned expenses. The adjustments increased Adjusted gross margin (as defined in Key Performance Metrics under Part II, Item 7 of this Form 10-K) by $5.8 million.
(3)Controllable Cash General and Administrative expenses (“G&A”), excludes restricted stock unit, bonus and benefits expense.
(4)System Availability is a measure of the “real” average availability experienced by WES’s customers related to its gas systems, oil systems, and water-disposal wells. It considers the ratio of average actual daily volumes to expected daily volumes and includes all experienced sources of downtime, such as scheduled and unscheduled downtime, logistic downtime, etc. The total availability score is a weighted average with more weight given to higher gross-margin-producing assets.
(5)Discretionary Growth Capital Spend represents accrual-based capital expenditures, including expenditures related to equity investments, and excludes maintenance capital expenditures (as defined in WES’s financial statements), capitalized interest, and capital expenditures associated with the 25% third-party interest in Chipeta.
(6)Leverage is calculated as the December 31, 2021, as principal debt outstanding divided by the trailing 12-months Adjusted EBITDA. Performance results reflect the Board’s discretion to exclude the impact of certain unplanned items on controllable cash costs and unbudgeted growth capital spend. These adjustments increased Adjusted EBITDA (as defined in Key Performance Metrics under Part II, Item 7 of this Form 10-K) by $48.9 million.
(7)Free cash flow performance results reflect the Board’s discretion to exclude expenses related to unbudgeted growth capital spend and certain unplanned items impacting controllable cash costs. These adjustments increased Free cash flow (as defined in Key Performance Metrics under Part II, Item 7 of this Form 10-K) by $136.3 million.
(8)Total Recordable Incident Rate (“TRIR”) includes injuries or illnesses that result in any of the following: days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness, or death.
(9)DART refers to Days Away, Restricted, or Transferred.
(10)Total Volumetric Spill Rate (“TVSR”) includes MSCF released plus BBL spilled/Total Operated BOE.
(11)Social Engagement includes employee volunteer participation through a WES coordinated event focused on local nonprofit organizations or individual volunteer time through a registered 501(c)3.
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2021 WCB Program Performance Assessment. In assessing the company’s performance under the WCB Program, the Board considered our performance against the pre-established targets for the year, as disclosed above, taking into consideration the impact of certain unplanned items, including, the impact of reportable COVID cases on our TRIR results, the impact of unbudgeted growth capital expenditures incurred during the year to support unplanned producer development and the financial impacts of winter storm Uri. After reviewing these specific quantifiable items, the Board determined it was appropriate to exercise its discretion and exclude their impact from the overall program results. After adjusting for these unplanned items and in recognition of the overall exceptional financial and operational performance, the Board approved a payout of 168% under the 2021 WCB Program. The Board believes this to be a measured and appropriate response to recognize WES’s collective performance in 2021 and is consistent with our compensation philosophy of rewarding absolute and relative performance and is aligned with the interest of unitholders by fostering the retention, motivation and engagement of employees.

Actual Bonuses Earned for 2021. The cash bonus awards for 2021 for our NEOs are shown in the table below and are reflected in the “Bonus” and “Non-Equity Incentive Plan Compensation” columns of the Summary Compensation Table.
Name
Target
Bonus ($)		Board Assessment of 2021 WCB ProgramCash Bonus
Awards ($)
Mr. Ure833,750x168%=1,400,700
Mr. Collins475,000x168%=798,000
Mr. Dial275,000x168%=462,000
Mr. Bourne330,000x168%=554,400
Mr. Griffie345,000x168%=579,600

Indirect Compensation Elements

As identified in the table below, the Partnership provides certain benefits and perquisites (considered indirect compensation elements) that are considered typical within our industry and necessary to attract and retain executive talent. The value of each element of indirect compensation is generally structured to be competitive within our industry.
Indirect Compensation ElementPrimary Purpose
Retirement Benefits
•Attracts talented executive officers and rewards them for extended service
•Offers secure and tax-advantaged vehicles for executive officers to save effectively for retirement
Other Benefits (for example, health care, paid time off, disability, and life insurance) and Perquisites
•Enhances executive welfare and financial security
•Provides a competitive package to attract and retain executive talent, but does not constitute a significant part of an executive officer’s compensation
Severance Benefits
•Attracts and helps retain executives in a volatile and consolidating industry
•Provides transitional income following an executive’s involuntary termination of employment
•In the event of a Change in Control, promotes management independence and helps retain, stabilize, and focus the executives


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Retirement Benefits. All of our employees, including our NEOs, are eligible to participate in the Western Midstream Savings Plan, a tax-qualified savings plan maintained by WES. In November 2021, our Board approved the Western Midstream Savings Restoration Plan, which is a non-qualified deferred compensation plan implemented to provide for the deferral of employer contributions that the participant would have otherwise been eligible for absent the Internal Revenue Code (“IRC”) limitations that restrict the amount of benefits payable under the tax-qualified savings plan. Prior to the implementation of the Savings Restoration Plan, the Board approved a one-time cash payment in 2021 to employees, including our NEOs, in the amount of employer contributions that would have been allocated to their savings plan account for their 2020 eligible earnings, without regard to the IRC limitations. Prior to 2020, our NEOs participated in retirement plans provided by their legacy employer (Occidental or Anadarko). Their participation in these plans ceased when their employment was transferred to the Partnership on December 31, 2019 and we are not responsible for any expense related to those prior benefits.

Other Benefits. We provide other benefits such as medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance, and disability coverage to our executive officers. These benefits are also provided to all other eligible U.S. based employees.

Perquisites. We provide a limited number of perquisites, including reimbursement of financial counseling, tax preparation, and estate planning services expense up to $4,000 annually, and reimbursement for the cost of personal excess liability insurance. The expenses related to the perquisites are imputed and considered taxable income to the executive officers, as applicable. We do not provide tax gross-ups on these perquisites. The incremental costs of the perquisites provided are included in the “All Other Compensation” column and supporting footnotes of the Summary Compensation Table.

Severance Benefits. In August 2021, our Board approved the Western Midstream Partners, LP Executive Severance Plan (the “ESP”) and the Western Midstream Partners, LP Executive Change in Control Severance Plan (the “CIC Plan”).

Executive Severance Plan. The ESP provides severance benefits to participants, including our NEOs, if their employment is terminated other than for “Cause” or if the participant resigns for “Good Reason.” Subject to a timely execution and non-revocation of a release of claims, participants are eligible for the following benefits:

•An amount equal to 2.0 times the sum of base salary and annual target bonus for the CEO and 1.5 times base salary and annual target bonus for the other NEOs;

•A prorated annual bonus for the year of termination, with payout based on actual performance;

•Continued participation in the Partnership’s basic life, medical, and dental plans at employee rates, for up to 24 months following termination;

•Prorated vesting of any unvested long-term incentive awards, including time-based and performance-based awards, with prorated performance awards based on actual performance under the original award agreement and paid at the end of the performance period;

•Outplacement services for up to nine months; and

•Any accrued, but unused as of the date of the termination, vacation pay;

Executive Change In Control Severance Plan. The CIC Plan provides severance benefits to participants, including our NEOs, if their employment is terminated other than for “Cause” or if the participant resigns for “Good Reason” on or after the date 180 days prior to the consummation of a Change in Control and within two years after the consummation of the Change in Control (“Protection Period”). Subject to a timely execution and non-revocation of a release of claims, participants are eligible for the following benefits:

•An amount equal to 2.99 times the sum of base salary and annual target bonus for the CEO and 2.0 times base salary and annual target bonus for the other NEOs;

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•A prorated bonus for the year of termination, determined based on the greater of target performance and actual performance;

•Continued participation in the Partnership’s basic life, medical, and dental plans at employee rates, for up to 24 months following termination;

•Full vesting of any unvested long-term incentive awards, including time-based and performance-based awards, with performance-based awards vesting at the greater of target and actual performance;

•Outplacement services for up to nine months; and

•Any accrued, but unused as of the date of the termination, vacation pay;

The ESP and CIC Plan became effective in August 2021, however, because we are still within the two-year change of control period triggered from the Occidental Merger until August 8, 2022, in certain termination scenarios an NEO may be eligible for severance benefits related to the legacy Anadarko Petroleum Corporation Amended and Restated Change of Control Severance Plan (“Anadarko COC Plan”). In the event an NEO triggers a severance benefit under both the Anadarko COC Plan and the ESP, they will receive the benefit under the plan that provides the greater benefits, in the aggregate. Under no circumstances, will an NEO receive duplicate severance benefits. A detailed discussion of the benefits under the new plans and any legacy programs is included in the Potential Payments Upon Termination or Change of Control section below, including a discussion of the ESP benefits payable to Mr. Griffie upon his departure from the Partnership on December 31, 2021.

Additional Compensation Policies and Provisions

The following provides a discussion of additional policies and provisions we have in place related to our overall executive compensation program.

Equity Grant Practices. WES maintains the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan, the Western Gas Partners, LP 2017 Long-Term Incentive Plan and the Western Midstream Partners, LP 2021 Long-Term Incentive Plan, which govern the issuance of equity and equity-based awards. Under the provisions of these plans, the Board has the authority to grant equity awards to our Section 16 officers. The grant date fair value of each award is based on the closing unit price of WES’s units on the NYSE on the grant date as designated by the Board. The grant date fair value of the TUR Units also incorporates the estimated payout percentage of the award on the grant date.

Equity Ownership Guidelines. In February 2021, in order to align the interests of executives and unitholders, the Board approved executive equity ownership guidelines as noted below. Executives are expected to comply with these guidelines within five years of the date the individual is first elected to the office. An officer who does not meet the minimum ownership guideline may not sell any Western Midstream units until he or she meets the guideline and would continue to meet the guideline following any such sale. In determining equity ownership levels, we include an executive’s direct unit holdings (including units held in a living trust or by a family partnership or corporation controlled by the executive, unless the executive expressly disclaims beneficial ownership of such units) and long-term incentive awards, including time-based restricted unit awards and vested performance unit awards. Unvested performance unit awards do not count towards the ownership guidelines.

PositionMultiple of Base Salary
Chief Executive Officer6
CFO/COO4
Other Senior Vice Presidents3
Vice Presidents1


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Clawback Provisions. Per the terms of our 2021 long-term incentive awards which were granted under the Western Gas Equity Partners, LP 2017 Long-Term Incentive Plan, if WES is required to prepare an accounting restatement due to the material noncompliance of the Partnership, as a result of misconduct, with any financial reporting requirement under the securities laws, and if the recipient knowingly engaged in the misconduct (whether or not they are an individual subject to automatic forfeiture under Section 304 of the Sarbanes-Oxley Act of 2002), the Board (or delegated Plan Administrator) may determine that the recipient must reimburse WES the amount of any payment in settlement of an award earned or accrued during the twelve-month period following the first public issuance or filing with the Securities and Exchange Commission (whichever first occurred) of the financial document embodying such financial reporting requirement.

Prohibition Against Derivative Transactions and Hedging. Our Insider Trading Policy expressly prohibits directors, officers and designated employees from directly or indirectly entering into equity derivative or other financial instruments (including, but not limited to, options, puts, calls, swaps, collars, forward contracts, hedges, exchange funds or short sales) tied to WES securities (including equity securities received as part of a compensation program as well as WES equity securities acquired personally).

Tax Law Considerations. We are a limited partnership for United States federal income tax purposes. Therefore, the compensation paid to our NEOs is not subject to the deduction limitations under Section 162(m) of the IRC. We have structured our compensation programs in a manner intended to be exempt from, or to comply with Section 409A of the IRC.

Compensation Committee Report

Although we formed a Compensation Committee in February 2022, the Committee was not engaged in the 2021 compensation process. During 2021, neither we nor our general partner had a compensation committee. The Board has reviewed and discussed the Compensation Discussion and Analysis set forth above with management and based on this review and discussion has approved it for inclusion in this Form 10-K.

The Board of Directors of Western Midstream Holdings, LLC:

Peter J. Bennett
Michael P. Ure
Oscar K. Brown
Nicole E. Clark
Frederick A. Forthuber
Kenneth F. Owen
David J. Schulte
Lisa A. Stewart
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EXECUTIVE COMPENSATION

Prior to 2020, we did not directly employ any of the persons responsible for managing or operating our business. Instead, we were managed by our general partner, and our executive officers were employees of Anadarko and Occidental. During this period, our reimbursement for the compensation of our executive officers was governed by the omnibus agreement. In December 2019, we executed several agreements with Occidental that enabled us to operate as a standalone business. Among these agreements was the Services Agreement, which transferred employment of WES’s management team from Occidental to WES.

Summary Compensation Table

The following table summarizes the compensation amounts expensed by us for our NEOs for the years ended December 31, 2021, 2020, and 2019. For 2019, the amounts reflect the portion of the compensation for our NEOs that was allocated to us by Anadarko and Occidental in accordance with the omnibus agreement.
Name and Principal PositionYear
Salary
($) (1)
Bonus
($) (2)
Stock
Awards
($) (3)
Non-Equity
Incentive Plan
Compensation
($) (4)
All Other
Compensation
($) (5)
Total
($)
Michael P. Ure2021713,462 416,041 6,259,276 984,659 344,607 8,718,045 
President, Chief Executive Officer2020641,346 617,500 4,133,602 — 42,439 5,434,887 
and Chief Financial Officer2019147,981 — 1,080,029 162,000 43,252 1,433,262 
Craig W. Collins2021471,923 237,025 2,575,436 560,975 204,045 4,049,404 
Senior Vice President and2020461,923 370,500 1,757,410 — 41,500 2,631,333 
Chief Operating Officer2019138,462 — 500,049 168,000 25,826 832,337 
Christopher B. Dial (6)
2021388,462 137,225 1,459,424 324,775 100,514 2,410,400 
Senior Vice President,
General Counsel and Secretary
Robert W. Bourne2021405,000 164,670 1,201,841 389,730 181,082 2,342,323 
Senior Vice President and2020417,692 313,500 981,448 — 41,725 1,754,365 
Chief Commercial Officer2019136,500 — 1,250,029 154,932 10,680 1,552,141 
Charles G. Griffie2021405,000 172,155 1,373,517 407,445 1,407,969 3,766,086 
Former Senior Vice President, 2020401,154 327,750 1,085,394 — 38,231 1,852,529 
Operations and Engineering201973,077 — 208,008 70,154 18,360 369,599 
________________________________________________________________
(1)For 2021 and 2020, the amounts reflect each officer’s full base salary expense. The 2019 amounts reflect the base salary expense allocated to us by Anadarko and Occidental in accordance with the omnibus agreement.
(2)For 2021, this column reflects the portion of the annual cash bonus awards that is attributed to the Board’s exercise of its discretion in assessing our performance results under the WCB Program for the year ended December 31, 2021, as discussed in the Compensation Discussion and Analysis. For 2020, this column reflects annual cash bonus awards under the WCB Program for the year ended December 31, 2020.
(3)For 2021 and 2020, this column reflects the aggregate grant date fair value of time-based units, ROA Units, and TUR Units, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures). The grant date fair value of the time-based units and ROA units equals the number of units granted multiplied by the WES closing unit price on the grant date. The grant date fair value of the TUR units is calculated based on a Monte-Carlo valuation on the grant date. The maximum values, assuming a 200% payout, of the 2021 ROA unit awards as of the grant date for Messrs. Ure, Collins, Dial, Bourne, and Griffie were approximately $3.5 million, $1.5 million, $0.85 million, $0.70 million, and $0.80 million, respectively. The maximum values, assuming a 200% payout, of the 2021 TUR unit awards as of the grant date for Messrs. Ure, Collins, Dial, Bourne, and Griffie were approximately $5.0 million, $2.2 million, $1.2 million, $1.0 million, and $1.1 million, respectively. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. The 2021 and 2020 amounts reflect the full grant date fair value of awards granted during the year. The 2019 amounts reflect the allocated grant date fair value of awards granted in 2019 in accordance with the omnibus agreement. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For information regarding the awards granted in 2021, see the Grants of Plan-Based Awards in 2021 table.
(4)For 2021, this column reflects the portion of the annual cash bonus awards calculated based on our unadjusted performance results, pursuant to the 2021 WCB Program. For 2019, the amounts reflect annual cash bonus compensation allocated to us for the year ended December 31, 2019 under the Anadarko and Occidental plans.

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(5)For 2019, 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 year. The 2021 amounts are detailed in the table below:
NamePayments by the Partnership to Employee 401(k) Plan and Savings Restoration Plan ($)Financial/Tax/Estate Planning ($)
Other ($) (i) (ii)
Total ($)
Michael P. Ure199,644 3,112 141,851 344,607 
Craig W. Collins126,363 4,000 73,682 204,045 
Christopher B. Dial86,305 3,134 11,075 100,514 
Robert W. Bourne122,145 1,775 57,162 181,082 
Charles G. Griffie124,568 4,000 1,279,401 1,407,969 
________________________________________________________________
(i)    For Messrs. Ure, Collins, Dial, and Bourne, the amounts reflect the one-time cash payments made by the Partnership in 2021 in the amount that would have been allocated to their savings plan account for their 2020 eligible earnings, without regard to the IRC limitations. Mr. Ure’s amount includes less than $500 in company-related spousal travel expense.
(ii) For Mr. Griffie, the amount includes his one-time cash payment, as described in the above footnote, of $130,841; benefits payable under the Executive Severance Plan in the amount of $1,125,000; and the payout upon his termination of his accrued but unused paid time off balance of $23,560.
(6)Mr. Dial was not an NEO for the years ended December 31, 2020 and 2019.

Grants of Plan-Based Awards in 2021

The following table sets forth information concerning annual cash incentive awards, equity incentive plan awards, and unit awards. The equity incentive plan and unit awards were granted pursuant to the Western Gas Equity Partners, LP 2017 Long-Term Incentive Plan during 2021 to each of the NEOs as described below.

Non-Equity Incentive Plan Awards (WCB Program). Values disclosed reflect the estimated cash payouts under the WES WCB Program, as discussed in the Compensation Discussion and Analysis. If threshold levels of performance are not met, the payout can be zero. If maximum levels of performance are achieved, the plan funding is capped at 200% of the aggregate target payout for all participants.

Equity Incentive Plan Awards (ROA Units and TUR Units). Values disclosed reflect grant date fair values for ROA Units and relative TUR Units, as discussed in the Compensation Discussion and Analysis. Officers may earn between 0% and 200% of the target awards based on WES’s performance and continued service over a three-year performance period ending December 31, 2023. Performance units earned are settled in the form of common units. The awards include tandem distribution equivalent rights accrued and paid in cash at the end of the performance period based on actual performance.

Time-Based Unit Awards. Values disclosed reflect grant date fair values for time-based unit awards that vest ratably over three years, beginning on February 12, 2022. The awards include tandem distribution equivalent rights paid in cash on a current basis.
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All Other 
Unit Awards:
Number of Units
(#)
Grant Date
Fair Value
of Unit Awards
($) (2)
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts Under
Equity Incentive Plan Awards
Name and 
Award Type		Grant DateThreshold
($)		Target
($)
Maximum
($) (1)
Threshold
(#)		Target
(#)		Maximum
(#)
Michael P. Ure— — 833,750 — — — — — — 
Time-Based Units02/18/2021— — — — — — 125,945 2,000,007 
ROA Units02/18/2021— — — 27,550 110,201 220,402 — 1,749,992 
TUR Units02/18/2021— — — 27,550 110,201 220,402 — 2,509,277 
Craig W. Collins— — 475,000 — — — — — — 
Time-Based Units02/18/2021— — — — — — 47,229 749,997 
ROA Units02/18/2021— — — 11,808 47,230 94,460 — 750,012 
TUR Units02/18/2021— — — 11,808 47,230 94,460 — 1,075,427 
Christopher B. Dial— — 275,000 — — — — — — 
Time-Based Units02/18/2021— — — — — — 26,763 424,996 
ROA Units02/18/2021— — — 6,691 26,764 53,528 — 425,012 
TUR Units02/18/2021— — — 6,691 26,764 53,528 — 609,416 
Robert W. Bourne— — 330,000 — — — — — — 
Time-Based Units02/18/2021— — — — — — 22,040 349,995 
ROA Units02/18/2021— — — 5,510 22,040 44,080 — 349,995 
TUR Units02/18/2021— — — 5,510 22,040 44,080 — 501,851 
Charles G. Griffie— — 345,000 — — — — — — 
Time-Based Units02/18/2021— — — — — — 25,189 400,001 
ROA Units02/18/2021— — — 6,297 25,188 50,376 — 399,985 
TUR Units02/18/2021— — — 6,297 25,188 50,376 — 573,531 
_________________________________________________________________________________________
(1)The non-equity incentive plan has a maximum overall funding of 200% of the aggregate target payout for all participants, but there are no individual maximums established.
(2)The amounts reflect the fair value on the grant date of the awards made to the NEOs in 2021 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.



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Outstanding Equity Awards at Year-End 2021

The following table reflects outstanding equity awards for each NEO as of December 31, 2021. The market values shown are based on WES’s closing unit price of $22.27 on December 31, 2021. The table excludes any prior outstanding awards granted under the Occidental LTIP Plan, as per the terms of the December 2019 Services Agreement, the Partnership no longer reimburses Occidental for the expense of these awards that were granted prior to 2020.
 Unit Awards
Equity Incentive Plan Awards
Restricted Units (1)
Performance Units (2)
 Number of
Units That Have
Not Vested
(#)		Market Value of Units That Have
Not Vested
($)		Number of Unearned Units
That Have Not Vested
(#)		Market or Payout
Value of Unearned Units That Have Not Vested
($)
Name
Michael P. Ure
Time-Based Units229,981 5,121,677 — — 
ROA Units— — 231,039 5,145,239 
TUR Units— — 207,977 4,631,648 
Craig W. Collins
Time-Based Units90,925 2,024,900 — — 
ROA Units— — 99,345 2,212,413 
TUR Units— — 89,470 1,992,497 
Christopher B. Dial
Time-Based Units49,651 1,105,728 — — 
ROA Units53,175 1,184,207 
TUR Units47,500 1,057,825 
Robert W. Bourne
Time-Based Units47,009 1,046,890 — — 
ROA Units— — 48,491 1,079,895 
TUR Units— — 43,936 978,455 
Charles G. Griffie
Time-Based Units— — — — 
ROA Units— — 24,516 545,971 
TUR Units— — 22,940 510,874 
_________________________________________________________________________________________
(1)The table below shows the vesting dates for the respective time-based units listed in the above Outstanding Equity Awards at Year-End 2021 Table:
Vesting DateMr. UreMr. CollinsMr. DialMr. Bourne
02/12/202294,000 37,591 20,365 19,830 
02/12/202393,999 37,591 20,365 19,832 
02/12/202441,982 15,743 8,921 7,347 
(2)The table below shows the performance periods for the respective ROA Units listed in the above Outstanding Equity Awards at Year-End 2021 Table. The number of outstanding ROA Units for each award is calculated based on WES’s return on assets performance as of December 31, 2021, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. WES’s performance to date as of December 31, 2021 under the ROA awards with a performance period ending December 31, 2022 was 146.3% and 147.5% for the awards with a performance period ending December 31, 2023.
Performance PeriodMr. UreMr. CollinsMr. DialMr. BourneMr. Griffie
1/1/2020 to 12/31/202268,49329,68113,69815,98212,166
1/1/2021 to 12/31/2023162,54669,66439,47732,50912,350
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(3)The table below shows the performance periods for the respective TUR Units listed in the above Outstanding Equity Awards at Year-End 2021 Table. The number of outstanding TUR Units for each award is calculated based on WES’s relative total unit return performance ranking as of December 31, 2021, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. WES’s performance to date as of December 31, 2021 under the TUR awards with a performance period ending December 31, 2022 was 150% and 125% for the awards with a performance period ending December 31, 2023.
Performance PeriodMr. UreMr. CollinsMr. DialMr. BourneMr. Griffie
1/1/2020 to 12/31/202270,226 30,432 14,045 16,386 12,474 
1/1/2021 to 12/31/2023137,75159,03833,45527,55010,466

Option Exercises and Units Vested in 2021

The following table reflects information about the aggregate dollar value realized during 2021 by our NEOs for WES awards that vested in 2021. The table below excludes the vesting of any prior awards granted under the Occidental LTIP, as per the terms of the December 2019 Services Agreement, the Partnership no longer reimburses Occidental for the expense of awards that were granted prior to 2020.
 Unit Awards
Name
Number of Units 
Acquired on Vesting
(#) (1)
Value Realized
on Vesting
($) (2)
Michael P. Ure65,637 1,126,164 
Craig W. Collins27,647 474,561 
Christopher B. Dial14,322 245,416 
Robert W. Bourne15,713 269,482 
Charles G. Griffie36,427 723,884 
_________________________________________________________________________________________
(1)The number of units acquired on vesting includes the time-based units that vested in 2021 and the distribution equivalent rights that, per the terms of the underlying 2020 award agreements, were settled in common units on the date of the distribution payments.
(2)The value realized on vesting represents the aggregate number of units that vested multiplied by the common unit price on the vesting date. The actual value ultimately realized by the officer, may be more or less than the value disclosed in the above table, depending upon the timing in which he held or sold the units associated with the vesting occurrence.

Pension Benefits for 2021

WES does not have a defined benefit pension plan that provides NEOs a fixed monthly retirement payment. Instead, all salaried employees on the U.S. dollar payroll, including the NEOs, are eligible to participate in a tax-qualified defined contribution plan.


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Nonqualified Deferred Compensation for 2021

Due to IRC limitations that restrict the amount of benefits payable under the tax-qualified 401(k) Plan, in November 2021, our Board approved the Western Midstream Savings Restoration Plan. The Savings Restoration Plan provides a benefit equal to the excess, if any, of the Partnership matching contributions that would have been allocated to a participant’s 401(k) Plan account each year without regard to IRC limitations. Eligible compensation includes base salary earnings and annual WCB payments. Participants may direct contributions into investment options that mirror those provided under the Partnership’s 401(k) Plan. In general, deferred amounts are distributed to the participant in lump sum upon separation from service.
Name
Executive Contributions in 2021
Company Contributions in 2021 (1)
Aggregate Earnings / Losses in 2021
Aggregate Withdrawal / Distributions in 2021
Aggregate Balance at End of 2021
Michael P. Ure$— $161,144 $— $— $161,144 
Craig W. Collins— 87,863 — — 87,863 
Christopher B. Dial— 47,805 — — 47,805 
Robert W. Bourne— 83,645 — — 83,645 
Charles G. Griffie— 89,768 — — 89,768 
_________________________________________________________________________________________
(1)Reflects contributions earned for fiscal year 2021, although not credited to participant accounts until 2022. These contributions are reported in the Summary Compensation Table for each of the NEOs under the “All Other Compensation” column for the year 2021.

Potential Payments Upon Termination or Change of Control

As of December 31, 2021, all of our NEOs were eligible for severance benefits under the ESP and CIC Plan that were approved by our Board in August 2021 (discussed in detail in the CD&A Severance section). In addition to these Plans, Messrs. Ure, Collins, Bourne and Dial remain eligible for certain benefits under the legacy Anadarko Petroleum Corporation Amended and Restated Change of Control Severance Plan (“Anadarko COC Plan”) until this plan expires on August 8, 2022 (the end of the two-year change of control period triggered by the Occidental Merger).
Pursuant to our current Services Agreement, we will not reimburse Occidental in cash for amounts related to the vesting of any outstanding equity or long-term incentive awards (whether vested, unvested, deferred, or otherwise) previously granted by Anadarko or Occidental to our NEOs, accordingly these awards are excluded from the disclosed amounts.
Upon Mr. Griffie’s departure from the Partnership on December 31, 2021, he received the following benefits under the ESP: cash severance of $1,125,000, payable in lump sum; an annual bonus for 2021 in the amount of $579,600, paid at the same time as other executives; up to two years of continued health and welfare benefits at the employee rates, valued at $41,702; and he is eligible for the reimbursement of up to nine months of outplacement services. Under the terms of his outstanding long-term incentive award agreements, he received a prorated portion of his unvested awards upon his departure, with an estimated value of $1,487,146. This value reflects the prorated time-based units that vested upon his departure and an estimated value of his prorated performance units, based on performance to date as of December 31, 2021. The performance units will be paid after the end of the performance period based on actual performance. Mr. Griffie will also be paid his previously earned and vested balance in the Savings Restoration Plan of $89,768. Mr. Griffie entered into a Release and Separation Agreement (“Release Agreement”) with WES setting out the terms of his departure. The Release Agreement also includes a release of claims, confidentiality, cooperation, non-solicitation, non-competition, and other provisions customary for an agreement of this type, with varying restricted periods ranging from 12 to 24 months.
The following tables reflect potential payments to our NEOs under existing plans and award agreements for various scenarios involving a change of control or termination of employment of each NEO, assuming a termination date of December 31, 2021 and, where applicable, using the closing price of our common unit of $22.27 (as reported on the NYSE as of December 31, 2021). In addition to the reported amounts, following a separation from service, NEOs would also receive any previously earned but not paid benefits under our Savings Restoration Plan, as disclosed in the Nonqualified Deferred Compensation for 2021 Table.
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Involuntary For Cause. For “cause” for purposes of the ESP and CIC Plan is generally defined as: (i) conviction of a felony or of a misdemeanor involving moral turpitude, (ii) willful failure to perform duties or responsibilities, (iii) engaging in conduct which is injurious (monetarily or otherwise) to the Partnership (or any affiliates), (iv) engaging in business activities which are in conflict with the business interests of the Partnership (or any affiliates), (v) insubordination, (vi) engaging in conduct which is in violation of any applicable policy or work rule, (vii) engaging in conduct in violation of applicable safety rules or standards, or (viii) engaging in conduct that is in violation of the applicable Code of Ethics and Business Conduct.
Mr. UreMr. CollinsMr. DialMr. Bourne
Cash Severance $— $— $— $— 
Total$— $— $— $— 

Involuntary Not For Cause Termination. As of December 31, 2021, the NEOs below were eligible for severance benefits under both the ESP and the broad-based Anadarko COC Plan in the event they are terminated without cause before the end of the change of control period defined under the Anadarko COC Plan, which is August 8, 2022. The original Anadarko COC Plan severance benefits were subject to a double-trigger; however, the Occidental Merger constituted a change of control of Anadarko for purposes of these arrangements and met the requirements for the first trigger. Accordingly, benefits are now subject only to the second trigger of an involuntary not for cause termination. If an NEO is eligible for severance benefits under the ESP and Anadarko COC Plan, they will receive the benefit under the plan that provides the greater benefits, in the aggregate. Under no circumstances, shall an NEO receive duplicate severance benefits.
Mr. UreMr. CollinsMr. DialMr. Bourne
Cash Severance (1)
$4,251,400 $2,546,000 $1,724,000 $1,918,800 
Pro-Rata Annual Cash Bonus (2)
833,750 475,000 275,000 330,000 
Pro-Rata Vesting of WES Equity Awards (3)
6,125,679 2,582,263 1,351,112 1,314,016 
Total$11,210,829 $5,603,263 $3,350,112 $3,562,816 
_________________________________________________________________________________________
(1)Reflects amounts payable in lump under the double-trigger broad-based rights extended to them under the Anadarko COC Plan.
(2)The amounts reflect a prorated annual bonus based on their target for the year, assuming each NEO’s employment terminated on December 31, 2021, pursuant to the rights extended to them under the Anadarko COC Plan.
(3)The amounts reflect the estimated current value of a prorated portion of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2021. In the event of an involuntary termination not for cause, the performance units would be paid after the end of the performance period, based on actual performance.

Good Reason Termination Under the ESP. As of December 31, 2021, the NEOs below were eligible for severance benefits in the event of a good reason termination under the ESP. Good Reason for purposes of the ESP is generally defined as the occurrence of any of the following conditions: materially and adversely diminished duties and responsibilities; a material reduction in base salary or base salary plus annual target bonus, unless such reduction is applied generally and consistently to the Partnership’s executives; or a material change in work location.
Mr. UreMr. CollinsMr. DialMr. Bourne
Cash Severance (1)
$3,117,500 $1,425,000 $1,012,500 $1,102,500 
Pro-Rata Annual Cash Bonus (2)
1,400,700 798,000 462,000 554,400 
Pro-Rata Vesting of WES Equity Awards (3)
— — — — 
Continuation of Welfare Benefits (4)
59,866 42,008 14,530 44,852 
Total$4,578,066 $2,265,008 $1,489,030 $1,701,752 
_________________________________________________________________________________________
(1)The cash severance is payable in lump sum, pursuant to the terms of the ESP. Mr. Ure’s value reflects 2.0 times the sum of his current base salary plus target bonus. The values for Messrs. Collins, Dial, and Bourne reflect 1.5 times the sum of their current base salary plus target bonus.
(2)Pursuant to the terms of the ESP, the values reflect a prorated annual bonus, assuming each NEO’s employment terminated on December 31, 2021.
(3)The current outstanding award agreements do not include a vesting provision for a good reason termination outside of a change of control.
(4)The amounts reflect the continuation of welfare benefits for two years at employee rates. The NEOs are also eligible for reimbursement of outplacement services for up to nine months following their separation.

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Change of Control: Involuntary Termination or Voluntary For Good Reason. The following table reflects benefits payable to the NEOs in the event of (i) a change of control of WES and (ii) a subsequent qualifying termination event. Unless otherwise noted, benefits are payable pursuant to the CIC Plan.
Under the CIC Plan, a change in control is deemed to have occurred in the event that: (i) any person or group other than the Partnership or Occidental (or affiliate) acquires more than 50% of the equity interests in the General Partner; (ii) the Partnership is subject to a plan of liquidation; (iii) the sale, transfer or other disposition of all or substantially all of the Partnership’s assets; (iv) certain changes are made to the composition of the Partnership’s Board of Directors; (v) the completion of a business combination transaction in which, after giving effect to such transaction, neither the Partnership, Occidental, nor its affiliates meet certain ownership thresholds; (vi) the General Partner is removed or the General Partner (or its affiliate) ceases to be the sole general partner of the Partnership; or the Partnership is taken private in a transaction in which its common equity securities cease to be listed on a national securities exchange.
Under the CIC Plan, Good Reason is generally defined as the occurrence of any of the following conditions without the participant’s consent: (i) diminution of duties and responsibilities; (ii) material reduction in compensation; (iii) change in work location of more than 50 miles; or (iv) in connection with a Change in Control, the failure by the acquiror to assume the Plan. Certain notice and cure conditions, as defined in the CIC Plan, apply in order for a termination for Good Reason to be effective.
Equity awards granted prior to the CIC Plan effective date are subject to the definitions in the applicable award agreements. Per the terms of those award agreements, a change of control is generally deemed to have occurred in the event: (i) any person or group other than the Partnership or Occidental (or affiliate) becomes the beneficial owner of more than 50% of the equity interests in the General Partner; (ii) of a complete liquidation of the Partnership; (iii) the sale or disposition of all or substantially all of the Partnership’s assets to any person other than an affiliate; or (iv) the General Partner (or affiliate) ceases to be the general partner of the Partnership and a single person or group other than the Partnership or Occidental (or affiliate) beneficially owns more than 50% of the general partner of the Partnership. The WES equity award agreements include “good reason” as a qualifying termination event, with “good reason” generally defined as any one of the following occurrences within two years of a change of control: (i) a diminution of duties and responsibilities; (ii) a material reduction in compensation; (iii) a material change in work location, as defined in the applicable agreement; or (iv) a requirement to travel for business to a substantially greater extent, with all occurrences compared to agreements in place immediately prior to the change of control.
Mr. UreMr. CollinsMr. DialMr. Bourne
Cash Severance (1)
$4,660,663 $1,900,000 $1,350,000 $1,470,000 
Pro-Rata Annual Cash Bonus (2)
1,400,700 798,000 462,000 554,400 
Accelerated Vesting of WES Equity Awards (3)
14,898,564 6,229,810 3,347,760 3,105,240 
Continuation of Welfare Benefits (4)
59,866 42,008 14,530 44,852 
Total$21,019,793 $8,969,818 $5,174,290 $5,174,492 
_________________________________________________________________________________________
(1)Reflects amounts payable in lump sum under the CIC Plan. Mr. Ure’s value is calculated as 2.99 times his base salary plus target bonus. The values for Messrs. Collins, Dial, and Bourne are calculated as 2.0 time their base salary plus target bonus.
(2)Per the terms of the CIC Plan, the NEOs are eligible for a prorated bonus for the year of termination, based on the greater of target performance and actual performance. The amounts reflect their actual bonuses awarded for 2021, as disclosed in the Summary Compensation Table.
(3)The amounts reflect the estimated current value of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2021. In the event of a change of control, the performance would be calculated based on the change of control date.
(4)The amounts reflect the continuation of welfare benefits for two years at employee rates. The NEOs are also eligible for reimbursement of outplacement services for up to nine months following their separation.

Death or Termination due to Disability
Mr. UreMr. CollinsMr. DialMr. Bourne
Accelerated Vesting of WES Equity Awards (1)
$14,898,564 $6,229,810 $3,347,760 $3,105,240 
Total$14,898,564 $6,229,810 $3,347,760 $3,105,240 
______________________________________________________________________________________
(1)The amounts reflect the estimated current value of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2021. In the event of death or termination due to disability, the performance units would be paid after the end of the performance period, based on actual performance.

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CEO Pay Ratio

Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, require disclosure regarding the relationship of the annual compensation of our employees and the annual compensation of Mr. Michael P. Ure, our Chief Executive Officer (CEO). As discussed in the Human Capital Resources section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K, as of December 31, 2021, we had 1,127 employees.
In accordance with Item 402(u) of Regulation S-K, we are using the same median employee that was identified for purposes of our 2020 disclosure contained in our 2020 Form 10-K as there has been no change in our employee population or employee compensation arrangements since that median employee was identified that we believe would significantly impact our pay ratio disclosure. We identified the median employee for 2020 by using base salary earnings for all employees, excluding our CEO, who were employed by us on December 31, 2020. We included all employees, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions, or adjustments to the data. We calculated annual total compensation for the median employee using the same methodology used for our NEOs as set forth in the above 2021 Summary Compensation Table. The pay ratio provided has been calculated as the total 2021 annual compensation for Mr. Ure of $8,718,045, divided by the total 2021 annual compensation of the median employee of $158,752. For 2021, the ratio resulting from this calculation was 55 to 1.

Director Compensation

Non-employee directors receive a combination of cash and stock-based compensation designed to attract and retain qualified candidates to serve on our Board. Officers or employees of Occidental who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. During 2021, the non-employee directors of our general partner received compensation for their Board service pursuant to a director compensation plan approved by the Board. To assist in the 2021 annual review of director compensation, the Board directly retained Meridian to provide benchmark compensation data and recommendations for the design of our non-employee director compensation program. The only change made to the program in 2021 was the elimination of an additional $2,000 meeting fee for each Board and committee meeting attended by the non-employee director in excess of 10 total Board and committee meetings in one calendar year.

Compensation for non-employee directors during 2021 consisted of the following:

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

•an annual retainer of $2,000 for each member of a committee of the Board, or $22,000 for the chair of such committee; and

•an annual grant of phantom units with a grant date fair value of approximately $125,000.

In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or committees and for costs associated with participation in continuing director education programs. Each director is fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.

Equity Ownership Guidelines. Non-employee directors of the General Partner are required to hold common units, phantom units, or related grants of such securities under the Partnership’s long-term incentive plans which have an aggregate value equivalent to three times the annual Board cash retainer. Directors have five years from the date of their initial election to the Board to comply with this requirement.
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The following table sets forth information concerning total director compensation earned during 2021 by each non-employee director:
NameFees Earned or Paid in Cash
($)
Stock
Awards 
($) (1)
Total
($)
Oscar K. Brown129,067 125,007 254,074 
Kenneth F Owen134,000 125,007 259,007 
David J. Schulte134,000 125,007 259,007 
Lisa A. Stewart114,000 125,007 239,007 
________________________________________________________________________________________
(1)The amounts included in the Stock Awards column represent the grant date fair value of phantom units made to directors in 2021, computed in accordance with FASB ASC Topic 718, based on the value of our common units on grant date. See the table below for phantom units awarded to each non-employee director during 2021. As of December 31, 2021, Messrs. Brown, Owen, and Schulte and Ms. Stewart each had 7,872 outstanding phantom units.

The table below contains the grant date fair value of phantom unit awards made to each non-employee director during 2021:
NameGrant Date
Phantom 
Units 
(#) (1)
Grant Date Fair 
Value of Stock Awards
($) (2)
Oscar K. BrownFebruary 187,872 125,007 
Kenneth F OwenFebruary 187,872 125,007 
David J. SchulteFebruary 187,872 125,007 
Lisa A. StewartFebruary 187,872 125,007 
_________________________________________________________________________________________
(1)The phantom units granted on February 18 will vest in full on February 12, 2022, subject to the director’s continued service through such date. Directors receive distribution equivalent rights, paid in cash on a quarterly basis, during the vesting period.
(2)The amounts included in the Grant Date Fair Value of Stock Awards column represent the grant date fair value of the awards made to non-employee directors in 2021 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the value included above.


Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s Board is not required to maintain, and does not maintain, a compensation committee. Messrs. Bennett and Forthuber, and Ms. Clark, who are directors of our general partner, are also executive or corporate officers of Occidental. However, all compensation decisions with respect to each of these persons are made by Occidental, and none of these individuals receive any compensation directly from us or our general partner for their service as directors. Read Part III, Item 13 below in this Form 10-K for information about relationships among us, our general partner, and Occidental.




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Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our common units held by the following as of February 17, 2022:

•each member of the Board;

•each named executive officer of our general partner;

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

•Occidental and its affiliates.
Name and Address of Beneficial Owner (1)
Common
Units
Beneficially Owned		Percentage of
Common Units
Beneficially
Owned
Occidental Petroleum Corporation (2)
200,281,578 49.6%
Peter J. Bennett— *
Michael P. Ure138,634 *
Robert W. Bourne31,498 *
Craig W. Collins73,853 *
Christopher B. Dial29,931 *
Catherine A. Green12,657 *
Oscar K. Brown (3)
17,115 *
Nicole E. Clark — *
Frederick A. Forthuber — *
Kenneth F. Owen 15,054 *
David J. Schulte 19,554 *
Lisa A. Stewart 15,054 *
All directors and executive officers
as a group (12 persons)		353,350 *
_________________________________________________________________________________________
*Less than 1%.
(1)The address for Occidental and its representatives on the Board of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380.
(2)WGRI owns 161,319,520 common units, AMH owns 457,849 common units, WGRAH owns 24,139,260 common units, and Anadarko USH1 Corporation owns 14,364,949 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)Includes 1,440 common units held in a margin account.


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The following table sets forth owners of 5% or greater of our common units, other than Occidental and its affiliates, the holdings of which are listed in the first table of this Item 12.
Title of ClassName and Address of Beneficial OwnerAmount and
Nature
of Beneficial
Ownership		Percent of Class
Common UnitsALPS Advisors, Inc.
1290 Broadway, Suite 1100
Denver, CO 80203
24,330,966 (1)
6.04%
_________________________________________________________________________________________
(1)Based upon its Schedule 13G filed February 3, 2022, with the SEC with respect to Partnership securities held as of December 31, 2021, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 24,330,966 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 24,192,551 of the common units held by ALPS.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information with respect to the securities that may be issued under the WES LTIPs as of December 31, 2021. For more information regarding the plans, read Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Plan Category(a)
Number of 
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants, and Rights 		(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants,
and Rights		(c)
Number of Securities
Remaining Available for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by security holders
1,118,191 (1)
— (2)
11,808,578 
Equity compensation plans not approved by security holders
1,958,349 (1)
— (2)
484,909 
Total3,076,540 — 12,293,487 
_________________________________________________________________________________________
(1)Includes performance units at their maximum payout of 200%.
(2)Phantom and performance units constitute the only rights outstanding under the WES LTIPs. Each phantom or performance unit that may be settled in common units entitles the holder to receive, upon vesting and determination of any performance criteria, if applicable, one common unit with respect to each phantom or performance unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.

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Item 13.  Certain Relationships and Related Transactions, and Director Independence

As of February 17, 2022, Occidental held (i) 200,281,578 of our common units, representing a 48.5% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.2% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGRAH.
We control, manage, and operate WES Operating through our ownership of WES Operating GP. We, directly and indirectly through our ownership of WES Operating GP, owned a 98.0% limited partner interest and the entire non-economic general partner interest in WES Operating.
The officers of our general partner are also officers of WES Operating GP and our general partner’s officers operate WES Operating’s business. Five of our directors are currently or formerly affiliated with Occidental and our remaining directors are independent as defined by the NYSE.

Agreements with Occidental

We, WES Operating, and other parties have entered into various agreements with Occidental as discussed below. These agreements were not the result of arm’s-length negotiations and, as such, they or the related underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding the transactions and agreements discussed below.

Summary of Material Related-Party Transactions

The following tables summarize material related-party transactions included in our consolidated financial statements (see Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K):
Consolidated statements of operations
Year Ended December 31,
thousands202120202019
Revenues and other
Service revenues – fee based$1,589,367 $1,740,999 $1,441,875 
Service revenues – product based11,888 8,509 7,062 
Product sales31,103 71,104 158,459 
Total revenues and other1,632,358 1,820,612 1,607,396 
Equity income, net – related parties (1)
204,645 226,750 237,518 
Operating expenses
Cost of product42,805 92,884 254,771 
Operation and maintenance27,805 49,533 146,990 
General and administrative (2)
15,613 40,295 101,485 
Total operating expenses86,223 182,712 503,246 
Gain (loss) on divestiture and other, net420 (2,870)— 
Interest income – Anadarko note receivable— 11,736 16,900 
Interest expense— (6)(1,970)
_________________________________________________________________________________________
(1)See Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)Includes (i) amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Item 13) and (ii) equity-based compensation expense allocated to us by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Item 13).

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Consolidated balance sheets
December 31,
thousands20212020
Assets
Accounts receivable, net$180,205 $291,253 
Other current assets12,490 5,493 
Equity investments (1)
1,167,187 1,224,813 
Other assets45,494 50,967 
Total assets1,405,376 1,572,526 
Liabilities
Accounts and imbalance payables49,242 6,664 
Accrued liabilities13,914 19,195 
Other liabilities207,365 138,796 
Total liabilities270,521 164,655 
_________________________________________________________________________________________
(1)See Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Consolidated statements of cash flows
Year Ended December 31,
thousands202120202019
Distributions from equity-investment earnings – related parties$213,516 $246,637 $234,572 
Capital expenditures(2,000)— (425)
Acquisitions from related parties— — (2,007,501)
Contributions to equity investments - related parties(4,435)(19,388)(128,393)
Distributions from equity investments in excess of cumulative earnings – related parties41,385 32,160 30,256 
APCWH Note Payable borrowings— — 11,000 
Repayment of APCWH Note Payable— — (439,595)
Distributions to Partnership unitholders (1)
(260,703)(367,861)(566,868)
Distributions to WES Operating unitholders (2)
(14,984)(15,434)(19,768)
Net contributions from (distributions to) related parties8,533 24,466 458,819 
Above-market component of swap agreements with Anadarko— — 7,407 
Finance lease payments— (6,382)(508)
Unit repurchases from Occidental (3)
(50,225)— — 
_________________________________________________________________________________________
(1)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).
(2)Represents distributions paid to Occidental, through its ownership of WGRAH, 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).
(3)We repurchased 2.5 million common units from Occidental during the year ended December 31, 2021 (see Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).


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The following tables summarize material related-party transactions for WES Operating (which are included in our consolidated financial statements) to the extent the amounts differ from our consolidated financial statements:

Consolidated statements of operations
Year Ended December 31,
thousands202120202019
General and administrative (1)
$18,365 $41,609 $99,613 
_________________________________________________________________________________________
(1)Includes (i) amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Item 13), (ii) equity-based compensation expense allocated to WES Operating by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Item 13), and (iii) an intercompany service fee between us and WES Operating.

Consolidated balance sheets
December 31,
thousands20212020
Accounts receivable, net$180,205 $246,083 
Accounts and imbalance payables (1)
97,749 6,664 
_________________________________________________________________________________________
(1)As of December 31, 2021, includes balances related to transactions between WES and WES Operating.

Consolidated statements of cash flows
Year Ended December 31,
thousands202120202019
Distributions to WES Operating unitholders (1)
$(749,018)$(771,546)$(1,025,931)
_________________________________________________________________________________________
(1)Represents distributions paid to us and Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement. Includes distributions made from WES Operating to WES during the years ended December 31, 2021 and 2020, that were used by WES to repurchase common units. 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.

Related-party revenues. Related-party revenues include amounts earned by us from services provided to Occidental and from the sale of natural gas, condensate, and NGLs to Occidental.

Gathering and processing agreements. We have significant gathering, processing, and produced-water disposal arrangements with affiliates of Occidental on most of our systems. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. For the year ended December 31, 2021, production owned or controlled by Occidental represented 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets.
We are currently involved in a dispute with Occidental regarding the calculation of the cost-of-service rates under an oil-gathering contract related to the Partnership’s DJ Basin oil-gathering system. If such dispute is resolved in a manner adverse to us, such resolution could have a negative impact on our financial condition and results of operations, including a reduction in rates and a non-cash charge to earnings.
In connection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to our Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation, now Mesquite Energy, Inc. (“Mesquite”) that allows Mesquite to process gas under such agreement. In December 2021, the Brasada gas processing agreement was assigned from Anadarko to Mesquite effective July 1, 2023. For this reason, Anadarko continues to be liable under the Brasada gas processing agreement until June 30, 2023, to the extent Mesquite does not perform. For all periods presented, Mesquite has performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.

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Further, in connection with the sale of its Uinta Basin assets in 2020, Kerr McGee Oil & Gas Onshore LP, a subsidiary of Occidental, retained the deficiency payment obligations under a gas processing agreement at the Chipeta plant. This contingent payment obligation extends through the earlier of October 1, 2022, or the termination of the processing agreement.

Marketing Transition Services Agreement. Effective December 31, 2019, certain subsidiaries of Anadarko entered into a transition services agreement (the “Marketing Transition Services Agreement”) to provide marketing-related services to certain of our subsidiaries through December 31, 2020, subject to the option to extend such services for an additional six-month period. The Marketing Transition Services Agreement was terminated on December 31, 2020. While we still have some marketing agreements with affiliates of Occidental, we began marketing and selling substantially all of our natural gas and NGLs directly to third parties beginning on January 1, 2021.

Operating leases. As a result of the surface-use and salt-water disposal agreements being amended under the CUA (see Related-party commercial agreement below), these agreements are now classified as operating leases and a $30.0 million ROU asset, included in Other assets on the consolidated balance sheets, was recognized during the first quarter of 2021. The ROU asset will be amortized to Operation and maintenance expense over the remaining term of the agreements.
Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of WES, the lessor, entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by us through December 31, 2021. In April 2021, we exercised the option to terminate the operating and maintenance agreement with Occidental effective December 31, 2021. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for field-related costs provided by related parties at certain of our assets. A portion of general and administrative expense is paid by Occidental, which results in related-party transactions pursuant to the reimbursement provisions of our and WES Operating’s agreements with Occidental. Cost of product expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and transactions with affiliates accounted for under the equity method of accounting. See Marketing Transition Services Agreement in the sections above. Related-party expenses do not bear a direct relationship to related-party revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

Services Agreement. General and administrative expense includes costs incurred pursuant to the agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP, under which Occidental has performed certain centralized corporate functions for us and WES Operating (“Services Agreement”).
Pursuant to the Services Agreement, which was amended and restated on December 31, 2019, specified employees of Occidental were seconded to WES Operating GP to provide, under the direction, supervision, and control of the general partner, (i) operating and routine maintenance service and (ii) corporate, administrative, and other services, with respect to the assets owned and operated by us. Occidental was reimbursed for the services provided by the seconded employees. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. In late March 2020, seconded employees’ employment was transferred to us. Most of the administrative and operational services previously provided by Occidental fully transitioned to us by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

Incentive Plans. General and administrative expense includes non-cash equity-based compensation expense allocated to us by Occidental for awards granted to the executive officers of the general partner and to other employees prior to their employment with us under (i) the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated, (ii) Occidental’s 2015 Long-Term Incentive Plan, and (iii) Occidental’s Phantom Share Unit Award Plan (collectively referred to as the “Incentive Plans”). General and administrative expense includes costs related to the Incentive Plans of $10.1 million, $14.6 million, and $12.9 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Construction reimbursement agreements and purchases from related parties. From time to time, we enter into construction reimbursement agreements with Occidental providing that we will manage the construction of certain midstream infrastructure for Occidental in our areas of operation. Such arrangements generally provide for a reimbursement of costs incurred by us on a cost or cost-plus basis.
Additionally, from time to time, in support of our business, we purchase equipment, inventory, and other miscellaneous assets, from Occidental or its affiliates.

Related-party commercial agreement. During the first quarter of 2021, an affiliate of Occidental and certain wholly owned subsidiaries of WES entered into a Commercial Understanding Agreement (“CUA”). Under the CUA, certain West Texas surface-use and salt-water disposal agreements were amended to reduce usage fees owed by us in exchange for the forgiveness of certain deficiency fees owed by Occidental and other unrelated contractual amendments. The present value of the reduced usage fees under the CUA was $30.0 million at the time the agreement was executed.

Indemnification agreements with directors and officers. Our general partner has entered into indemnification agreements with each of its officers and directors (each, an “Indemnitee”). The indemnification agreements provide that each Indemnitee will be indemnified and held harmless against all expense, liability, and loss (including attorney’s fees, judgments, fines or penalties, and amounts to be paid in settlement) actually and reasonably incurred or suffered by the Indemnitee in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its Board to the fullest extent permitted by applicable law, including Section 18-108 of the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. The indemnification agreements also provide that advance payment of certain expenses must be made to the Indemnitee, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.
Through December 31, 2021, there have been no payments or claims to Occidental related to these indemnification agreements and no payments or claims have been received from Occidental related to these indemnification agreements.

Chipeta LLC agreement. We are party to the Chipeta LLC agreement, together with a third-party member. Among other things, the Chipeta LLC agreement provides the following:

•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.

We are the managing member of Chipeta. As managing member, we manage the day-to-day operations of Chipeta and receive a management fee from the other member, which is intended to compensate the managing member for the performance of its duties. We may be removed as the managing member only if we are grossly negligent or fraudulent, breach our primary duties, or fail to respond in a commercially reasonable manner to written business proposals from the other member, and such behavior, breach, or failure has a material adverse effect to Chipeta.

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Review, Approval, or Ratification of Transactions with Related Persons

Our Audit Committee generally reviews transactions between WES and its directors, executive officers, or their immediate family members, or significant equity holders involving, in any case, amounts in excess of $120,000. However, our Board may also request that certain transactions between WES and Occidental, or our general partner, be reviewed by the Special Committee pursuant to our partnership agreement, as described in more detail below.
Whenever a conflict arises between our general partner or its related parties, including Occidental, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve the conflict. Our partnership agreement contains provisions that modify and limit our general partner’s default state law fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of fiduciary duties otherwise applicable under state law. See Special Committee under Part III, Item 10 of this Form 10-K.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is any of the following:

•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.

Our general partner may, but in most circumstances is not required to, seek the approval of such resolution from the Special Committee of its Board. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Special Committee and its Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, our general partner or the Special Committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. Our partnership agreement provides that for someone to act in good faith, that person must reasonably believe he is acting in the best interests of the Partnership.
Additionally, the Board has adopted a written Code of Ethics and Business Conduct (the “Code”), under which all directors and officers of the general partner, and employees working on our behalf, are expected to avoid conflicts or the appearance of conflicts in relation to their duties and responsibilities to us, and report any violation of the Code by any person. Under our Corporate Governance Guidelines, any waivers of the Code for any officer or director may only be made by the Board or by a committee of the Board composed of independent directors.

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Item 14.  Principal Accounting Fees and Services

We have engaged KPMG LLP as our and WES Operating’s independent registered public accounting firm. The following table presents fees for the audit of the annual consolidated financial statements for the last two fiscal years and for other services provided by KPMG LLP:
WESWES Operating
thousands2021202020212020
Audit fees$400 $250 $2,100 $2,240 
Total$400 $250 $2,100 $2,240 

Audit fees are primarily for the audit of our and WES Operating’s consolidated financial statements, including the audit of the effectiveness of internal control over financial reporting, consents, comfort letters, other audits, and the reviews of financial statements included in the Forms 10-Q. Audit-related fees are primarily for certain financial accounting consultations.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of our general partner has adopted a Pre-Approval Policy with respect to services that may be performed by KPMG LLP. This policy lists specific audit-related services and any other services that KPMG LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2021, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee. During 2021, the Audit Committee reviewed and approved the use of KPMG LLP’s Accounting research and disclosure checklist applications for no additional fee.
The Audit Committee has approved the appointment of KPMG LLP as independent registered public accounting firm to conduct the audit of our and WES Operating’s consolidated financial statements for the year ended December 31, 2022.

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PART IV

Item 15.  Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of this Form 10-K. For a listing of these statements and accompanying footnotes, see the Index to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(a)(2) Financial Statement Schedules

Financial statement schedules have been omitted because they are not required, not applicable, or the information is included under Part II, Item 8 of this Form 10-K.

(a)(3) Exhibits

Exhibit Index
Exhibit
Number		Description
#2.1
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
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Exhibit
Number		Description
3.10
3.11
3.12
3.13
*4.1
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
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Exhibit
Number		Description
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
10.1
10.2
10.3
10.4
10.5
‡10.6
10.7
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Exhibit
Number		Description
10.8
10.9
10.10
10.11
10.12
‡10.13
‡10.14
‡10.15
‡10.16
‡10.17
‡10.18
‡10.19
‡10.20
†10.21
10.22
10.23
10.24
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Exhibit
Number		Description
10.25
10.26
10.27
10.28
†10.29
†10.30
†10.31
†10.32
†10.33
†10.34
10.35
*21.1
*23.1
*23.2
24.1
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Exhibit
Number		Description
*31.1
*31.2
**32.1
**32.2
*101.INSXBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
*101.SCHInline XBRL Schema Document
*101.CALInline XBRL Calculation Linkbase Document
*101.DEFInline XBRL Definition Linkbase Document
*101.LABInline XBRL Label Linkbase Document
*101.PREInline XBRL Presentation Linkbase Document
*104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
______________________________________________________________________________________
*Filed herewith
**Furnished herewith
#Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
†Portions of this exhibit have been omitted as confidential pursuant to Item 601(b)(10) of Regulation S-K or a request for confidential treatment.
‡Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

Item 16.  Form 10-K Summary

    Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
 
WESTERN MIDSTREAM PARTNERS, LP
February 23, 2022
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
February 23, 2022
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)

Each person whose signature appears below constitutes and appoints Michael P. Ure his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or the substitute or substitutes of may lawfully do or cause to be done by virtue hereof.

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 23, 2022.

SignatureTitle (Position with Western Midstream Holdings, LLC)
/s/ Peter J. BennettChairman
Peter J. Bennett
/s/ Michael P. UrePresident, Chief Executive Officer, Chief Financial Officer and Director
Michael P. Ure(Principal Executive and Financial Officer)
/s/ Catherine A. GreenSenior Vice President and Chief Accounting Officer
Catherine A. Green(Principal Accounting Officer)
/s/ Oscar K. BrownDirector
Oscar K. Brown
/s/ Nicole E. ClarkDirector
Nicole E. Clark
/s/ Frederick A. Forthuber Director
Frederick A. Forthuber
/s/ Kenneth F. OwenDirector
Kenneth F. Owen
/s/ David J. SchulteDirector
David J. Schulte
/s/ Lisa A. StewartDirector
Lisa A. Stewart

200