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Western Midstream Partners, LP - Annual Report: 2022 (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, 2022

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
☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Western Midstream Partners, LP
¨
Western Midstream Operating, LP
¨
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
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, 2022, based on the closing price as reported on the New York Stock Exchange.
Western Midstream Partners, LP$4.9 billion
Western Midstream Operating, LPNone
Common units outstanding as of February 16, 2023:
Western Midstream Partners, LP384,892,309
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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1 and 2.
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1B.
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5.
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7A.
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9.
9A.
9B.
9C.
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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.
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.
Bcf/d: Billion cubic feet per day.
Board: The board of directors of WES’s general partner.
Cactus II: Cactus II Pipeline LLC, in which we held a 15% interest that we sold in November 2022 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
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.
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.
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EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see Reconciliation of Non-GAAP Financial Measures 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.
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, in which we held a 14.81% interest that we sold in October 2020 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
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, in which we own a 33.33% interest.
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.
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.
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, in which we own a 50% interest.
MLP: Master limited partnership.
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MMcf: Million cubic feet.
MMcf/d: Million cubic feet per day.
Mont Belvieu JV: Enterprise EF78 LLC, in which we own a 25% interest.
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, in which we own a 15% interest.
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.
Ranch Westex: Ranch Westex JV LLC, in which we owned a 50% interest through August 2022, and a 100% interest thereafter (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
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.
Red Bluff Express: Red Bluff Express Pipeline, LLC, in which we own a 30% interest.
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, in which we own a 22% interest.
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, in which we own a 20% interest.
SEC: U.S. Securities and Exchange Commission.
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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.
SOFR: Secured Overnight Financing Rate.
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, in which we own a 20% interest.
TEP: Texas Express Pipeline LLC, in which we own a 20% interest.
Term loan facility: WES Operating’s senior unsecured credit facility, which was entered into in December 2018 and 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.
WGRAH: WGR Asset Holding Company LLC.
WGRI: Western Gas Resources, Inc., a subsidiary of Occidental.
White Cliffs: White Cliffs Pipeline, LLC, in which we own a 10% interest.
Whitethorn LLC: Whitethorn Pipeline Company LLC, in which we own a 20% interest.
Whitethorn: A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC.
$1.25 billion Purchase Program: In February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024. In November 2022, the Board authorized an increase in the program to $1.25 billion. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.
$250.0 million 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 were purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. As of December 31, 2021, the entire $250.0 million authorized program had been fulfilled.
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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, 2022 (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-20221231_g1.jpg

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As of December 31, 2022, 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/trains25 3 — 3 
NGLs pipelines2 — — 5 
Natural-gas pipelines6 — — 1 
Crude-oil pipelines3 1 — 3 
_________________________________________________________________________________________
(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, 2022:
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 Disposal4,317895,81531 %1,9401,9951,890 270 853 
Transportation1,966— — — — 307 268 — 
Rocky MountainsGathering, Processing, and Treating5,995558,843 50 %3,120 214 1,944 82 — 
Transportation2,263— — — — 90 70 — 
North-central PennsylvaniaGathering17115,180 — %— — 135 — — 
Total14,7121,469,838 38 %5,060 2,209 4,366 690 853 
_________________________________________________________________________________________
(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, 2022, 2021, and 2020, and total assets for the years ended December 31, 2022 and 2021.

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ACQUISITIONS AND DIVESTITURES

Cactus II. In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. Total proceeds were received during the fourth quarter of 2022, resulting in a net gain on sale of $109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

Ranch Westex. In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million. Subsequent to the acquisition, (i) we are the sole owner and operator of the asset, (ii) Ranch Westex is no longer accounted for under the equity method of accounting, and (iii) the Ranch Westex processing plant is included as part of the operations of the West Texas complex. 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 core assets and 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. We intend to maintain our focus on generating efficiencies between our commercial, engineering, and operations teams, as well as optimizing and maximizing 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.

•Generating stable cash flows. We intend to continue generating low-volatility cash flows through commodity-price cycles by pursuing fee-based contracts with risk-reducing protections in place, such as minimum-volume commitments and cost-of-service provisions.

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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.

•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, 2022. 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) actual recoveries differ from contractual recoveries under certain of our processing agreements or (ii) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facility. In addition, we mitigate volumetric risk through minimum-volume commitments and cost-of-service contract structures. For the year ended December 31, 2022, we had approximately 3.0 Bcf/d for our natural-gas assets (excluding equity investments), approximately 460 MBbls/d for our crude-oil and NGLs assets (excluding equity investments), and approximately 760 MBbls/d for our produced-water assets that 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, 2022, there was $1.6 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.

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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.

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, 2022, Occidental held (i) 190,281,578 of our common units, representing a 48.4% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.3% 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, 2022, Occidental held 49.5% of our outstanding common units.
For the year ended December 31, 2022, 55% of Total revenues and other, 35% 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 80% 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 agreements with affiliates of Occidental, on January 1, 2021, we began marketing and selling substantially all of our crude oil and residue gas, and a majority of our NGLs, directly to third parties.
Pursuant to the Services Agreement entered into on December 31, 2019, Occidental has performed certain centralized corporate functions for the Partnership and WES Operating. 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-20221231_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 generally does not vary with commodity-price changes, thereby minimizing the service provider’s direct commodity-price risk exposure, except to the extent that (i) drip condensate that is recovered during the gathering of natural gas from the wellhead or production facility is retained and sold or (ii) actual recoveries differ from contractual recoveries under certain processing agreements.

•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, 2022.

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, & Treating15 1,540 53 621,741 3 1,906 
West Texas
DBM oil system (5)
Gathering & Treating16 — 292 24,723 1 644 
West TexasDBM water systemsGathering & Disposal— — 1,390 74,217 5 835 
West Texas
Mi Vida (6)
Processing1 200 — 20,000 — — 
East Texas
Mont Belvieu JV (7)
Processing2 — 170 — — — 
South TexasBrasada complex Gathering, Processing, & Treating3 200 15 29,400 1 58 
South Texas
Springfield system (8)
Gathering & Treating3 — 75 125,734 2 874 
Total401,9401,995895,815124,317
_________________________________________________________________________________________
(1)Includes 115 MMcf/d of bypass capacity at the West Texas complex.
(2)Includes owned and leased compressors and compression horsepower.
(3)Includes 28 miles of transportation related to the 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, DBJV and Haley systems, and the Ranch Westex processing plant.
(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 25% interest in the Mont Belvieu JV, which owns two NGLs fractionation trains. A third party serves as the operator.
(8)We own a 50.1% interest in the Springfield system and serve as the operator.

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West Texas and New Mexico
wes-20221231_g3.jpg

West Texas gathering, processing, and treating complex

•Customers. For the year ended December 31, 2022, Occidental’s production represented 44% of the West Texas complex throughput, and the largest third-party customer provided 18% 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 Mi Vida plant (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, Whitewater Midstream, LLC’s Agua Blanca pipeline, Oasis pipeline, Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”), and 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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•Mentone Train III. WES is currently constructing a third cryogenic processing train at the Mentone processing plant at the West Texas complex. Mentone Train III will have a capacity of 300 MMcf/d, and WES expects this train to be completed in the fourth quarter of 2023. Upon completion of Mentone Train III, the West Texas complex will have a total processing capacity of 1,840 MMcf/d.

DBM oil-gathering system, treating facilities, and storage

•Customers. As of December 31, 2022, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2022, Occidental’s production represented 98% 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. As of December 31, 2022, DBM water systems throughput was from Occidental and numerous third-party producers, with Occidental’s production representing 80% 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, 2022, 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. NGLs production is delivered to the Lone Star pipeline.
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East Texas
wes-20221231_g4.jpg

Mont Belvieu JV fractionation trains

•Customers. The Mont Belvieu JV does not contract with customers directly but is allocated volumes from Enterprise Products Partners L.P. (“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 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
wes-20221231_g5.jpg

Brasada gathering, stabilization, treating, and processing complex

•Customers. For the year ended December 31, 2022, Brasada complex throughput was from two third-party customers.

•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, 2022, Springfield system throughput was from multiple 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 has a delivery point to our Brasada complex and other interruptible points (the Raptor processing plant owned by Carnero G&P LLC and operated by Targa Resources Corp. and the Dos Hermanos plant owned and operated by ET). The oil-gathering system delivers oil 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 1,750 59 364,176 2 2,139 
ColoradoDJ Basin oil systemGathering & Treating6 — 155 6,095 1 446 
Utah
Chipeta (4)
Processing3 790 — 76,125 — 2 
Total252,540214446,39632,587
_________________________________________________________________________________________
(1)Includes 200 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, Wattenberg, Lancaster Trains I and II, and Latham Trains I and II processing plants, and the Wattenberg gathering system.
(4)We are the managing member of and own a 75% interest in Chipeta, which owns the Chipeta processing complex.

Colorado
wes-20221231_g6.jpg
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DJ Basin gathering, treating, and processing complex

•Customers. For the year ended December 31, 2022, Occidental’s production represented 54% of the DJ Basin complex throughput, and the two largest third-party customers provided 31% of the throughput.

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

•Delivery points. As of December 31, 2022, 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, 2022, 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
wes-20221231_g7.jpg

Chipeta processing complex

•Customers. For the year ended December 31, 2022, Chipeta complex throughput was from numerous third-party customers, with the two largest customers providing 81% of the throughput.

•Supply. Chipeta’s inlet is connected to Caerus Oil and Gas LLC’s Greater Natural Buttes gathering system, the MountainWest Pipeline, LLC system (“MountainWest 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 Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas, and ultimately to the NGLs fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has residue gas delivery points through the CIG pipeline, MountainWest 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 37,866 1 1,203 
Southwest Wyoming
Granger complex (1)
Gathering & Processing4 520 45,050 1 788 
Southwest WyomingRed Desert complexGathering— — 21,131 1 1,117 
Southwest Wyoming
Rendezvous (2)
Gathering— — 8,400 1 300 
Total6580112,44743,408
_________________________________________________________________________________________
(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.

wes-20221231_g8.jpg

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Northeast Wyoming

Hilight gathering system and processing plant

•Customers. For the year ended December 31, 2022, gas gathered and processed at the Hilight system was from third-party customers, with the two largest customers providing 55% 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, 2022, Granger complex throughput was from third-party customers, with the two largest customers providing 78% 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”);
◦MountainWest 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, 2022, Red Desert complex throughput was from third-party customers, with the three largest customers providing 48% 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, 2022, 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 MountainWest 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)
Gathering15,180 3 171 
_________________________________________________________________________________________
(1)We own a 33.75% interest in the Marcellus Interest gathering systems.

wes-20221231_g9.jpg

Marcellus gathering systems

•Customers. As of December 31, 2022, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided approximately 88% of the throughput for the year ended December 31, 2022. Capacity not used by priority shippers is available to other third parties as determined by the operating partner, a subsidiary of EQT Corporation.

•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

wes-20221231_g10.jpg

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LocationAssetTypeOwnership InterestPipeline Miles
Colorado, Kansas, Oklahoma
White Cliffs (1) (2)
Oil & NGLs10.00 %1,070 
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 %234 
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
Red Bluff Express (1) (2)
Gas30.00 %120 
Total4,229 
_________________________________________________________________________________________
(1)Regulated by FERC.
(2)Operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline

•Customers. The White Cliffs dual pipeline system had multiple committed shippers, including Occidental, as of December 31, 2022. 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, 2022. 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 four primary shippers on the GNB NGL pipeline as of December 31, 2022. 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, 2022, throughput on the MIGC system was from numerous third-party customers, with the three 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 Black Hills Corporation’s Cheyenne Light Fuel & Power and several industrial users.

OTTCO transportation system

•Customers. For the year ended December 31, 2022, 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 30 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, 2022, 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, 2022, 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, 2022.

•Texas Express Pipeline. TEP delivers to Enterprise’s NGL fractionation and storage facility 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, 2022, 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 and connects with Enterprise’s Rancho II pipeline in Sealy to deliver into ECHO storage and greater Houston market. 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, 2022, the Panola pipeline had multiple committed shippers. The Panola pipeline provides capacity to other shippers at the posted FERC-based rates.

Red Bluff Express pipeline

•Customers. As of December 31, 2022, 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, WES 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.

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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, (ii) the safety of hazardous liquid pipelines, and (iii) enhanced emergency-order procedures. The gas-transmission rule (i.e., the first of the three parts of the Mega 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 the second 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. In August 2022, PHMSA released the third and final part of the Mega Rule. This rule increases corrosion control requirements, requires inspections following extreme weather events, extends the management of change process to non-high consequence areas, and strengthens repair criteria. The final part of the Mega Rule will become effective in May 2023 with certain implementation deadlines starting in February 2024.
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 West Texas complex residue lines (exiting our Ramsey and Ranch Westex processing plants) 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, 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. Pending appellate review could result in a further change to the index. An indexed rate is subject to challenge if the increase is substantially in excess of changes in the pipeline’s operating costs. 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. A pipeline also can support a rate by showing that it has been agreed to by all shippers or by obtaining advance approval to charge market-based rates. Both White Cliffs and Saddlehorn pipelines have been granted market-based rate authority by the FERC.
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 indexed or 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 West Texas complex 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. FERC makes jurisdictional determinations on a case-by-case basis. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. 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.

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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 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. In November 2022, the EPA issued a supplemental proposal to update, strengthen, and expand its November 2021 proposal. 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% - 52% below 2005 levels by 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 producing or 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 has issued regulations governing the issuance of underground injection-control permits that limit the maximum injection pressure, rate, and volume of water. Similarly, the Texas Railroad Commission has adopted rules for wastewater disposal wells that impose certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and seismic activity, and has also issued directives requiring certain wells to restrict or suspend disposal-well operations near where faults exist or where seismic events have occurred. 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, 2022, WES employed 1,217 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 2022 voluntary attrition rate was 11.43%, which we believe is reasonable for our industry and market conditions during the year.
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. We have also implemented social involvement and volunteering programs to support our people and the communities in which we live and work.
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.
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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;

•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, 2022, 55% of Total revenues and other, 35% 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 80% 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 its commercial agreements with us. 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 conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and
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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. 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. For example, WES Operating currently has $3.1 billion of outstanding senior notes that provide for changes to the coupon rates following changes in WES Operating’s credit ratings. 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, 2022, 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 and volatility of such 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, during 2020, oil and natural-gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. Although commodity prices have recovered from those lows, they remain subject to volatility that could negatively impact 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 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
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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.
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 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 and in connection with the war in Ukraine. 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. Continued inflation has raised our costs for labor, materials, fuel, and services, thereby increasing our operating costs and capital expenditures, and these costs may continue to increase. While we cannot predict any future trends in the rate of inflation, the aforementioned factors have brought significant uncertainty to the near-term economic outlook. Further increases in inflation would raise our costs for labor, materials, fuel, 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 2022 distribution of $0.50000 per unit per quarter, or $2.00000 per unit per year, we require per-quarter available cash of $196.6 million, or $786.4 million per year, based on the number of common units outstanding at February 1, 2023. 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.
Certain of our natural-gas processing agreements provide our producer customers with contractually specified NGL recoveries that, under expected operating conditions, may generate commodity price exposure and could, under certain circumstances, generate financial or physical-delivery obligations for us.
Under certain of our natural-gas processing agreements, we provide our producer customers with contractually specified NGL recoveries. To the extent actual recoveries exceed the contractually specified recoveries, we retain the excess NGL volumes and sell such volumes for our own account along with NGL and natural-gas volumes retained by us under our percent-of-proceeds and keep-whole processing agreements, bearing commodity-price risk on these volumes.
Conversely, if actual plant recoveries are below the contractually specified recoveries, we would still be obligated to deliver the contractually fixed amount of NGLs (or in some cases, the financial equivalent thereof) to such customers. For this reason, our inability to efficiently operate our natural-gas processing facilities could result in diminished NGL sale proceeds for our account, or could result in losses when we settle shortfalls between actual and contractually specified recoveries with our customers. Accordingly, the failure to achieve operational plant efficiency to support the contractually specified recoveries could negatively impact our profitability and cash flows available for distribution to unitholders.
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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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. This 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. Additional Senate Bill 19-181 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.
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 producing or 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.
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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. While the oil and gas industry has rebounded from the lows seen in 2020, the repricing of credit risk and the relatively weak industry conditions in recent years have made, and will likely continue to make, it difficult for some entities to obtain funding. Future downturns in our industry could increase our cost of obtaining financing from the credit markets as a result of increased rates of return required by many lenders and institutional investors. In such a situation, our lenders could tighten lending standards, refuse to provide funding on terms similar to our current debt, or reduce, or in some cases, refuse to provide funding. 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.
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.
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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.
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. 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.
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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.
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.
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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 also 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 or 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. In addition, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by COVID-19 lockdowns or geopolitical events, such as the Russian invasion of Ukraine), which may result in the suspension of operations of the impacted assets until such activities can be completed. Any significant increase in maintenance and repair expenditures, loss of revenue due to the age or condition of our pipeline systems, or delays in completing necessary maintenance or repairs 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) 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
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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 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.
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.
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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 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.
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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 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 384,070,984 common units outstanding as of December 31, 2022. Occidental currently holds 190,281,578 common units, representing 49.5% 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 7.9% of our common units as of December 31, 2022, 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.
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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.
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
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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 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
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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. As a result, distributions to non-U.S. unitholders will be reduced by withholding taxes at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. Additionally, distributions to non-U.S. unitholders occurring on or after January 1, 2023, will be subject to an additional 10% withholding tax on the amount of any distribution in excess of our cumulative net income that has not been previously distributed. The determination of cumulative net income is complex and unclear in certain respects, and we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to the additional 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.
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 for transfers of interests in a publicly traded partnership occurring on or after January 1, 2023, 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 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
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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.

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. We are currently exploring global resolution of the claims. While such resolution would likely include an injunctive relief component and payment of a civil penalty, which may exceed the disclosure threshold amount required by Item 103 of Regulation S-K, management believes the resolution of these claims will not have a material impact on WES’s results of operations, cash flows, or financial condition.
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 treated 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.
On November 22, 2022, WGR filed suit against Enterprise Crude Oil LLC (“ECO”) in the District Court of Harris County, Texas. Our lawsuit alleges that ECO breached a contract related to the Whitethorn joint venture pursuant to which ECO must share with WGR certain of the profits and losses generated by ECO’s hydrocarbon trading activity conducted utilizing the Whitethorn pipeline. Specifically, we claim that ECO has engaged in trades knowing that the revenue to be realized would be less than the minimum floor set under the contract and has failed to allocate revenues and expenses as prescribed by the contract, resulting in improper losses to WGR. Enterprise has filed a counterclaim to our lawsuit, alleging that, between 2017 and 2019, it had mistakenly overpaid WGR approximately $12.0 million in trading profits and seeking recovery of such amount. 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 16, 2023, there were 23 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 outside directors, executive officers, and employees under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “2017 LTIP”) and the Western Midstream Partners, LP 2021 Long-Term Incentive Plan (the “2021 LTIP”). The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 9,500,000 units, respectively, of which 1,928,415 and 9,500,000 units, respectively, remained available for future issuance as of December 31, 2022. 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 $1.25 billion Purchase Program during the fourth quarter of 2022:
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, 2022523,858 $25.93 523,858 $539,340,520 
November 1-30, 2022175,422 26.79 175,422 784,641,400 
December 1-31, 2022850,668 26.13 850,668 762,409,380 
Total1,549,948 26.14 1,549,948 
______________________________________________________________________________________
(1)In February 2022, WES announced a $1.0 billion purchase program, pursuant to which we may purchase up to $1.0 billion in aggregate value of our common units through December 31, 2024. In November 2022, the Board authorized an increase in the program to $1.25 billion. 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, 2022, our general partner owned a 2.3% 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, 2022 (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, 2022, 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
25 3 — 3 
NGLs pipelines2 — — 5 
Natural-gas pipelines
6 — — 1 
Crude-oil pipelines
3 1 — 3 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

Significant financial and operational events during the year ended December 31, 2022, included the following:

•WES Operating redeemed the $502.2 million total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value.

•We repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased from Occidental, for an aggregate purchase price of $487.6 million. In November 2022, the Board authorized an increase in the repurchase program from $1.0 billion to $1.25 billion.

•Our fourth-quarter 2022 per-unit distribution is unchanged from the third-quarter 2022 per-unit distribution of $0.50000.

•In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing.

•In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million.

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•Natural-gas throughput attributable to WES totaled 4,210 MMcf/d for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021.

•Crude-oil and NGLs throughput attributable to WES totaled 676 MBbls/d for the year ended December 31, 2022, representing a 3% increase compared to the year ended December 31, 2021.

•Produced-water throughput attributable to WES totaled 836 MBbls/d for the year ended December 31, 2022, representing a 19% increase compared to the year ended December 31, 2021.

•Gross margin was $2.2 billion for the year ended December 31, 2022 representing a 12% increase compared to the year ended December 31, 2021. See Reconciliation of Non-GAAP Financial Measures within this Item 7.

•Adjusted gross margin for natural-gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.32 per Mcf for the year ended December 31, 2022, representing a 6% increase compared to the year ended December 31, 2021.

•Adjusted gross margin for crude-oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.46 per Bbl for the year ended December 31, 2022, representing an 8% increase compared to the year ended December 31, 2021.

•Adjusted gross margin for produced-water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.94 per Bbl for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021.

The following table provides additional information on throughput for the periods presented below:
Year Ended December 31,
20222021Inc/
(Dec)		2020Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin1,470 1,256 17 %1,297 (3)%
DJ Basin1,331 1,369 (3)%1,305 5 %
Equity investments483 463 4 %445 4 %
Other1,082 1,215 (11)%1,386 (12)%
Total throughput for natural-gas assets
4,366 4,303 1 %4,433 (3)%
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin198 183 8 %189 (3)%
DJ Basin82 90 (9)%101 (11)%
Equity investments373 366 2 %381 (4)%
Other37 33 12 %41 (20)%
Total throughput for crude-oil and NGLs assets
690 672 3 %712 (6)%
Throughput for produced-water assets (MBbls/d)
Delaware Basin853 717 19 %712 1 %
Total throughput for produced-water assets
853 717 19 %712 1 %
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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, 2022, our West Texas and DJ Basin assets provided (i) 52% and 32%, respectively, of Total revenues and other, (ii) 38% and 34%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 62% and 26%, 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, 2022, 55% of Total revenues and other, 35% 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 80% 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.
For the year ended December 31, 2022, 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 certain of our 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 alter drilling or production schedules in certain areas, which could cause variability in 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, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see Reconciliation of Non-GAAP Financial Measures 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, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services.

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.

Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures associated with growth and maintenance projects is closely monitored. Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved.

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. 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 Reconciliation of Non-GAAP Financial Measures 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.
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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. In addition, certain of our natural-gas processing agreements provide our producer customers with the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows. See Risk Factors under Part I, Item 1A of this Form 10-K.

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 Reconciliation of Non-GAAP Financial Measures 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 $20.6 million, $30.5 million, and $203.9 million for the years ended December 31, 2022, 2021, and 2020, 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. In December 2019, we executed several agreements with Occidental that enabled us to operate as a standalone business. 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.

Acquisitions and divestitures. In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. Total proceeds were received during the fourth quarter of 2022, resulting in a net gain on sale of $109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million. Subsequent to the acquisition, (i) we are the sole owner and operator of the asset, (ii) Ranch Westex is no longer accounted for under the equity method of accounting, and (iii) the Ranch Westex gas processing plant is included as part of the operations of the West Texas complex.
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.
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,
thousands202220212020
Total revenues and other (1)
$3,251,721 $2,877,155 $2,772,592 
Equity income, net – related parties183,483 204,645 226,750 
Total operating expenses (1)
1,950,992 1,745,573 2,129,063 
Gain (loss) on divestiture and other, net103,676 44 8,634 
Operating income (loss)1,587,888 1,336,271 878,913 
Interest income – Anadarko note receivable— — 11,736 
Interest expense(333,939)(376,512)(380,058)
Gain (loss) on early extinguishment of debt91 (24,944)11,234 
Other income (expense), net1,603 (623)1,025 
Income (loss) before income taxes1,255,643 934,192 522,850 
Income tax expense (benefit)4,187 (9,807)5,998 
Net income (loss)1,251,456 943,999 516,852 
Net income (loss) attributable to noncontrolling interests34,353 27,707 (10,160)
Net income (loss) attributable to Western Midstream Partners, LP (2)
$1,217,103 $916,292 $527,012 
_________________________________________________________________________________________
(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, 2022” refer to the comparison of the year ended December 31, 2022, to the year ended December 31, 2021, and 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.

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Throughput
Year Ended December 31,
20222021Inc/
(Dec)		2020Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation409 466 (12)%543 (14)%
Processing3,474 3,374 3 %3,445 (2)%
Equity investments (1)
483 463 4 %445 4 %
Total throughput4,366 4,303 1 %4,433 (3)%
Throughput attributable to noncontrolling interests (2)
156 155 1 %159 (3)%
Total throughput attributable to WES for natural-gas assets
4,210 4,148 1 %4,274 (3)%
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation317 306 4 %331 (8)%
Equity investments (1)
373 366 2 %381 (4)%
Total throughput690 672 3 %712 (6)%
Throughput attributable to noncontrolling interests (2)
14 13 8 %14 (7)%
Total throughput attributable to WES for crude-oil and NGLs assets
676 659 3 %698 (6)%
Throughput for produced-water assets (MBbls/d)
Gathering and disposal853 717 19 %712 1 %
Throughput attributable to noncontrolling interests (2)
17 14 21 %14 — %
Total throughput attributable to WES for produced-water assets
836 703 19 %698 1 %
_________________________________________________________________________________________
(1)Represents our share of average throughput for investments accounted for under the equity method of accounting.
(2)For all periods presented, includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

Natural-gas assets

Gathering, treating, and transportation throughput decreased by 57 MMcf/d for the year ended December 31, 2022, 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 in the areas around the Marcellus Interest systems. These decreases were offset partially by higher volumes at the MIGC system.
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 the area around the Marcellus Interest systems.
Processing throughput increased by 100 MMcf/d for the year ended December 31, 2022, primarily due to higher volumes at the West Texas complex due to increased production in the area. This increase was offset partially by (i) lower volumes due to production declines in areas around the DJ Basin and Granger complexes and (ii) lower volumes at the Brasada complex due to downstream issues causing volumes to be diverted away from the plant during 2022.
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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Equity-investment throughput increased by 20 MMcf/d for the year ended December 31, 2022, primarily due to increased volumes on Red Bluff Express due to increased production in the area. This increase was offset partially by (i) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition (see Acquisitions and Divestitures within this Item 7), and (ii) decreased volumes at the Rendezvous system due to production declines in the area.
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.

Crude-oil and NGLs assets

Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes at the DBM oil system resulting from increased production in the area, partially offset by lower volumes at the DJ Basin oil system resulting from production declines in the area.
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.
Equity-investment throughput increased by 7 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes on FRP resulting from increased pipeline commitments. This increase was offset partially by (i) lower volumes on the Cactus II pipeline, which was sold to two third parties in the fourth quarter of 2022, and (ii) decreased volumes on the Whitethorn pipeline.
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.

Produced-water assets

Gathering and disposal throughput increased by 136 MBbls/d for the year ended December 31, 2022, due to higher production and new third-party connections brought online during the fourth quarter of 2021 and in 2022.
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.

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Service Revenues
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
Service revenues – fee based$2,602,053 $2,462,835 6 %$2,584,323 (5)%
Service revenues – product based249,692 122,584 104 %48,369 153 %
Total service revenues$2,851,745 $2,585,419 10 %$2,632,692 (2)%

Service revenues – fee based

Service revenues – fee based increased by $139.2 million for the year ended December 31, 2022, primarily due to increases of (i) $63.1 million at the West Texas complex due to increased throughput, partially offset by a lower average gathering fee primarily due to a cost-of-service rate redetermination effective January 1, 2022, (ii) $59.7 million at the DBM oil system due to increased throughput, increased deficiency fees, and the treatment of lease revenue under the operating and maintenance agreement with Occidental that was terminated effective December 31, 2021, (iii) $44.8 million at the DBM water systems due to increased throughput and increased deficiency fees, (iv) $9.2 million at the Marcellus Interest systems due to a higher average gathering fee, partially offset by decreased throughput, and (v) $8.2 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021, partially offset by decreased throughput. These increases were offset partially by decreases of (i) $31.7 million at the DJ Basin complex due to decreased throughput, partially offset by increased deficiency fees, and (ii) $4.9 million at the Springfield system primarily due to lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021.
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 – product based

Service revenues – product based increased by $127.1 million for the year ended December 31, 2022, primarily due to increases of (i) $81.4 million at the West Texas complex attributable to increases in pricing and volumes, along with changes in contract mix, (ii) $38.5 million at the DJ Basin complex due to changes in contract mix, and (iii) $4.2 million and $3.0 million at the DBM water systems and MGR assets, respectively, due to increases in pricing and volumes.
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.
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Product Sales
Year Ended December 31,
thousands except percentages and per-unit amounts20222021Inc/
(Dec)		2020Inc/
(Dec)
Natural-gas sales
$129,187 $83,102 55 %$30,527 172 %
NGLs sales269,836 207,845 30 %108,032 92 %
Total Product sales$399,023 $290,947 37 %$138,559 110 %
Per-unit gross average sales price:
Natural gas (per Mcf)$5.66 $4.31 31 %$1.45 197 %
NGLs (per Bbl)40.51 33.69 20 %13.14 156 %

Natural-gas sales

Natural-gas sales increased by $46.1 million for the year ended December 31, 2022, primarily due to increases of $45.7 million, $7.1 million, and $4.1 million at the West Texas complex, MGR assets, and Granger complex, respectively, attributable to increased average prices and volumes sold. These increases were offset partially by a decrease of $14.1 million at the DJ Basin complex due to decreased volumes sold, partially offset by an increase in average prices.
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.

NGLs sales

NGLs sales increased by $62.0 million for the year ended December 31, 2022, primarily due to increases of (i) $31.4 million and $3.5 million at the DJ Basin and Granger complexes, respectively, due to an increase in average prices, partially offset by a decrease in volumes sold, and (ii) $14.5 million at the West Texas complex, $12.5 million at the Chipeta complex, and $4.4 million at the DBM water systems, attributable to increased average prices and volumes sold. These increases were offset partially by a decrease of $5.1 million at the Brasada complex due to a contract expiration in the third quarter of 2022.
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).

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Equity Income, Net – Related Parties
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
Equity income, net – related parties$183,483 $204,645 (10)%$226,750 (10)%

Equity income, net – related parties decreased by $21.2 million for the year ended December 31, 2022, primarily due to decreases of (i) $9.9 million at Saddlehorn due to decreases in revenues along with increases in operating expenses, (ii) $9.0 million at Ranch Westex, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition (see Acquisitions and Divestitures within this Item 7), (iii) $8.4 million at Whitethorn LLC due to decreases in volumes resulting in lower revenues, (iv) $6.5 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Acquisitions and Divestitures within this Item 7), and (v) $4.5 million at Mont Belvieu JV due to increases in operating expenses, partially offset by increases in revenue. These decreases were offset partially by increases of $8.1 million and $7.6 million at TEP and FRP, respectively, due to increased volumes resulting in higher revenues.
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.

Cost of Product and Operation and Maintenance Expenses
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
Residue purchases$173,104 $146,709 18 %$65,193 125 %
NGLs purchases320,739 187,231 71 %131,964 42 %
Other(72,943)(11,655)NM(9,069)29 %
Cost of product420,900 322,285 31 %188,088 71 %
Operation and maintenance654,566 581,300 13 %580,874 — %
Total Cost of product and Operation and maintenance expenses$1,075,466 $903,585 19 %$768,962 18 %
_________________________________________________________________________________________
NM—Not meaningful

Residue purchases

Residue purchases increased by $26.4 million for the year ended December 31, 2022, primarily due to increases of (i) $15.3 million at the West Texas complex attributable to increased volumes purchased and average prices, as well as changes in contract mix during 2022, (ii) $10.1 million at the Chipeta complex due to increased volumes purchased and average prices, and (iii) $6.1 million and $4.7 million at the MGR assets and the Granger complex, respectively, primarily attributable to increased average prices. These increases were offset partially by a decrease of $9.5 million at the DJ Basin complex primarily due to a change in contract mix during the second quarter of 2022.
Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.7 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).
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NGLs purchases

NGLs purchases increased by $133.5 million for the year ended December 31, 2022, primarily due to increases of (i) $76.7 million at the West Texas complex due to increased volumes purchased and average prices, as well as a change in contract mix during the second quarter of 2022, (ii) $58.5 million at the DJ Basin complex attributable to increased average prices and a change in contract mix during the second quarter of 2022, and (iii) $4.2 million at the DBM water systems due to increased average prices and volumes purchased. These increases were offset partially by a decrease of $4.6 million at the Brasada complex due to a contract expiration in the third quarter of 2022.
NGLs purchases increased by $55.3 million for the year ended December 31, 2021, primarily due to increases of (i) $53.3 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) $35.2 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).

Other items

Other items decreased by $61.3 million for the year ended December 31, 2022, primarily due to decreases of $45.8 million and $21.0 million at the West Texas and DJ Basin complexes, respectively, attributable to changes in imbalance positions. These decreases were offset partially by an increase of $5.5 million at the MGR assets attributable to changes in imbalance positions.
Other items decreased by $2.6 million for the year ended December 31, 2021, primarily due to a decrease of $25.4 million at the DJ Basin complex due to changes in imbalance positions, partially offset by increases of $16.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions.

Operation and maintenance expense

Operation and maintenance expense increased by $73.3 million for the year ended December 31, 2022, primarily due to increases of (i) $15.4 million in chemicals and treating services, (ii) $14.8 million for maintenance and repair expense, (iii) $10.8 million for mechanical-integrity costs, (iv) $9.5 million for salaries and wages costs, (v) $9.4 million in regulatory and environmental expense, (vi) $9.1 million in utility expense, (vii) $7.3 million in land-related costs, and (viii) $4.2 million in water-disposal costs. These increases were offset partially by a decrease of $8.0 million in contract labor and consulting expense.
Operation and maintenance expense increased by $0.4 million for the year ended December 31, 2021, primarily due to increases of (i) $21.0 million attributable to higher utility expense, (ii) $6.4 million due to higher field-area costs, and (iii) $4.0 million in vehicle costs. These increases were offset partially by decreases of (i) $7.9 million attributable to lower contract labor and consulting expense, (ii) $6.7 million in water-disposal costs, (iii) $6.3 million due to lower regulatory and environmental expense, (iv) $5.9 million due to other operating costs, and (v) $4.5 million due to lower maintenance and repair expense.
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Other Operating Expenses
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
General and administrative$194,017 $195,549 (1)%$155,769 26 %
Property and other taxes78,559 64,267 22 %68,340 (6)%
Depreciation and amortization582,365 551,629 6 %491,086 12 %
Long-lived asset and other impairments
20,585 30,543 (33)%203,889 (85)%
Goodwill impairment— — — %441,017 (100)%
Total other operating expenses$875,526 $841,988 4 %$1,360,101 (38)%

General and administrative expenses

General and administrative expenses decreased by $1.5 million for the year ended December 31, 2022, primarily due to a decrease of $7.1 million in contract and consulting costs, primarily related to information technology services and fees incurred in 2021, partially offset by an increase of $5.9 million in personnel costs, including increased bonus-related expenses and other miscellaneous employee 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.

Property and other taxes

Property and other taxes increased by $14.3 million for the year ended December 31, 2022, primarily due to increases in the state assessed portion of ad valorem property values resulting in increases for the DJ Basin complex.
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.

Depreciation and amortization expense

Depreciation and amortization expense increased by $30.7 million for the year ended December 31, 2022, primarily due to (i) $14.2 million at the DJ Basin complex due to an acceleration of depreciation expense for revised service-life assumptions, (ii) $10.5 million resulting from capital projects being placed into service, (iii) $4.1 million of increased expense at the Hilight system, and (iv) $3.7 million at a transportation asset in Southwest Wyoming primarily as a result of a change in estimate for asset retirement obligations. These increases were offset partially by a decrease in depreciation expense of $3.3 million at the MGR assets.
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.

Long-lived asset and other impairment expense

Long-lived asset and other impairment expense for the year ended December 31, 2022, was primarily due to a $19.9 million other-than-temporary impairment of our investment in White Cliffs.
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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
For further information on our equity investments and other-than-temporary impairments, see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 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.

Interest Income – Anadarko Note Receivable and Interest Expense
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
Interest income – Anadarko note receivable$— $— — %$11,736 (100)%
Long-term and short-term debt
$(326,949)$(366,570)(11)%$(369,815)(1)%
Finance lease liabilities(414)(861)(52)%(1,516)(43)%
Commitment fees and amortization of debt-related costs(12,212)(12,705)(4)%(13,501)(6)%
Capitalized interest5,636 3,624 56 %4,774 (24)%
Interest expense$(333,939)$(376,512)(11)%$(380,058)(1)%

Interest income
Interest income - Anadarko note receivable decreased by $11.7 million for the year ended December 31, 2021, 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 $42.6 million for the year ended December 31, 2022, primarily due to decreases of (i) $21.3 million primarily due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 and 5.375% Senior Notes due 2021 during the second quarter of 2022 and first quarter of 2021, respectively, (ii) $16.8 million due to credit-rating related interest rate changes on the 4.050% Senior Notes due 2030 and 5.250% Senior Notes due 2050, (iii) $13.5 million due to credit-rating related interest rate changes and a lower outstanding balance on the 3.100% Senior Notes due 2025, and (iv) $2.7 million due to a lower outstanding balance on the 3.950% Senior Notes due 2025, a portion of which was repaid during the third quarter of 2021. These decreases were offset partially by an increase of $13.6 million due to higher outstanding borrowings and average interest rates under the RCF during 2022.
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 during the first quarter of 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.
See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.
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Income Tax Expense (Benefit)
Year Ended December 31,
thousands except percentages20222021Inc/
(Dec)		2020Inc/
(Dec)
Income (loss) before income taxes$1,255,643$934,19234 %$522,85079 %
Income tax expense (benefit)4,187(9,807)(143)%5,998NM
Effective tax rate— %NM1 %

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.
For the years ended December 31, 2022 and 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability. 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.

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

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).

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

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.

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Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure 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 that are most directly comparable to Adjusted EBITDA. The GAAP measure 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,
thousands202220212020
Reconciliation of Gross margin to Adjusted gross margin
Total revenues and other$3,251,721 $2,877,155 $2,772,592 
Less:
Cost of product420,900 322,285 188,088 
Depreciation and amortization582,365 551,629 491,086 
Gross margin2,248,456 2,003,241 2,093,418 
Add:
Distributions from equity investments250,050 254,901 278,797 
Depreciation and amortization582,365 551,629 491,086 
Less:
Reimbursed electricity-related charges recorded as revenues81,764 74,405 79,261 
Adjusted gross margin attributable to noncontrolling interests (1)
73,632 67,850 65,835 
Adjusted gross margin$2,925,475 $2,667,516 $2,718,205 
_________________________________________________________________________________________
(1)For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests.


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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.
Year Ended December 31,
thousands except per-unit amounts202220212020
Gross margin
Gross margin for natural-gas assets (1)
$1,676,732 $1,536,163 $1,537,075 
Gross margin for crude-oil and NGLs assets (1)
346,406 287,391 354,784 
Gross margin for produced-water assets (1)
245,274 197,821 213,834 
Per-Mcf Gross margin for natural-gas assets (2)
1.05 0.98 0.95 
Per-Bbl Gross margin for crude-oil and NGLs assets (2)
1.38 1.17 1.37 
Per-Bbl Gross margin for produced-water assets (2)
0.79 0.76 0.82 
Adjusted gross margin
Adjusted gross margin for natural-gas assets
$2,031,600 $1,882,726 $1,820,926 
Adjusted gross margin for crude-oil and NGLs assets
607,769 547,134 647,390 
Adjusted gross margin for produced-water assets
286,106 237,656 249,889 
Per-Mcf Adjusted gross margin for natural-gas assets (3)
1.32 1.24 1.16 
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (3)
2.46 2.28 2.54 
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.94 0.93 0.98 
_________________________________________________________________________________________
(1)Excludes corporate-level depreciation and amortization.
(2)Average for period. Calculated as Gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.
(3)Average for period. Calculated as Adjusted Gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.

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Year Ended December 31,
thousands202220212020
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)$1,251,456 $943,999 $516,852 
Add:
Distributions from equity investments250,050 254,901 278,797 
Non-cash equity-based compensation expense
27,783 27,676 22,462 
Interest expense333,939 376,512 380,058 
Income tax expense4,187 4,403 10,278 
Depreciation and amortization582,365 551,629 491,086 
Impairments (1)
20,585 30,543 644,906 
Other expense555 1,468 1,953 
Less:
Gain (loss) on divestiture and other, net103,676 44 8,634 
Gain (loss) on early extinguishment of debt91 (24,944)11,234 
Equity income, net – related parties183,483 204,645 226,750 
Interest income – Anadarko note receivable— — 11,736 
Other income1,648 585 2,785 
Income tax benefit— 14,210 4,280 
Adjusted EBITDA attributable to noncontrolling interests (2)
54,049 49,901 50,607 
Adjusted EBITDA$2,127,973 $1,946,690 $2,030,366 
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities$1,701,426 $1,766,852 $1,637,418 
Interest (income) expense, net333,939 376,512 368,322 
Accretion and amortization of long-term obligations, net
(7,142)(7,635)(8,654)
Current income tax expense (benefit)2,188 (37)2,702 
Other (income) expense, net(1,603)623 (1,025)
Cash paid to settle interest-rate swaps
— — 25,621 
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Changes in assets and liabilities:
Accounts receivable, net116,296 (16,366)193,688 
Accounts and imbalance payables and accrued liabilities, net7,812 (114,887)(144,437)
Other items, net(34,791)(49,856)(24,822)
Adjusted EBITDA attributable to noncontrolling interests (2)
(54,049)(49,901)(50,607)
Adjusted EBITDA$2,127,973 $1,946,690 $2,030,366 
Cash flow information
Net cash provided by operating activities$1,701,426 $1,766,852 $1,637,418 
Net cash used in investing activities(218,237)(257,538)(448,254)
Net cash provided by (used in) financing activities(1,398,532)(1,752,237)(844,204)
_________________________________________________________________________________________
(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% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests.

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Year Ended December 31,
thousands202220212020
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities$1,701,426 $1,766,852 $1,637,418 
Less:
Capital expenditures487,228 313,674 423,602 
Contributions to equity investments – related parties9,632 4,435 19,388 
Add:
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Free cash flow$1,268,463 $1,490,128 $1,226,588 
Cash flow information
Net cash provided by operating activities$1,701,426 $1,766,852 $1,637,418 
Net cash used in investing activities(218,237)(257,538)(448,254)
Net cash provided by (used in) financing activities(1,398,532)(1,752,237)(844,204)

Gross margin. Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenues, Product Sales, Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
Gross margin increased by $245.2 million for the year ended December 31, 2022, due to a $374.6 million increase in total revenues and other, partially offset by (i) a $98.6 million increase in cost of product and (ii) a $30.7 million increase in depreciation and amortization.
Gross margin decreased by $90.2 million for the year ended December 31, 2021, due to (i) a $134.2 million increase in cost of product and (ii) a $60.5 million increase in depreciation and amortization. These amounts were offset partially by a $104.6 million increase in total revenues and other.

Net income (loss). Refer to Operating Results within this Item 7 for a discussion of the primary components of Net income (loss) as compared to the prior periods.
Net income (loss) increased by $307.5 million for the year ended December 31, 2022, primarily due to (i) a $374.6 million increase in total revenues and other, (ii) a $103.6 million increase in gain (loss) on divestiture and other, net, and (iii) a $42.6 million decrease in interest expense. These amounts were offset partially by a $205.4 million increase in total operating expenses.
Net income (loss) increased by $427.1 million for the year ended December 31, 2021, primarily due to (i) a $383.5 million decrease in total operating expenses and (ii) a $104.6 million increase in total revenues and other.

Net cash provided by operating activities. Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods.

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KEY PERFORMANCE METRICS
Year Ended December 31,
thousands except percentages and per-unit amounts20222021Inc/
(Dec)		2020Inc/
(Dec)
Adjusted gross margin$2,925,475 $2,667,516 10 %$2,718,205 (2)%
Per-Mcf Adjusted gross margin for natural-gas assets (1)
1.32 1.24 6 %1.16 7 %
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (1)
2.46 2.28 8 %2.54 (10)%
Per-Bbl Adjusted gross margin for produced-water assets (1)
0.94 0.93 1 %0.98 (5)%
Adjusted EBITDA2,127,973 1,946,690 9 %2,030,366 (4)%
Free cash flow1,268,463 1,490,128 (15)%1,226,588 21 %
_________________________________________________________________________________________
(1)Average for period. Calculated as Adjusted gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.

Adjusted gross margin. Adjusted gross margin increased by $258.0 million for the year ended December 31, 2022, primarily due to (i) strong plant performance and contract mix leading to increased product recoveries, coupled with higher commodity prices and increased throughput at the West Texas complex, partially offset by a lower average gathering fee primarily due to a cost-of-service rate redetermination effective January 1, 2022, (ii) increased throughput and deficiency fee revenues at the DBM water and DBM oil systems, (iii) a higher average gathering fee at the Marcellus Interest systems, partially offset by decreased throughput, and (iv) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 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), partially offset by decreased throughput. These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC and (ii) lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021 at the Springfield system.
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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Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.08 for the year ended December 31, 2022, primarily due to strong plant performance and contract mix leading to increased product recoveries, coupled with higher commodity prices and increased throughput at the West Texas 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 $0.08 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-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.18 for the year ended December 31, 2022, primarily due to (i) increased throughput and increased deficiency fee revenues at the DBM oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021 at the DJ Basin oil system, and (iii) an increase in distributions from Cactus II. These increases were offset partially by (i) lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021 at the Springfield system, (ii) a decrease in distributions from Saddlehorn and Whitethorn LLC, and (iii) increased throughput on FRP, which has a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs 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 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. Adjusted EBITDA increased by $181.3 million for the year ended December 31, 2022, primarily due to a $374.6 million increase in total revenues and other. This amount was offset partially by (i) a $98.4 million increase in cost of product expense (net of lower of cost or market inventory adjustments), (ii) a $73.3 million increase in operation and maintenance expenses, (iii) a $14.3 million increase in property taxes, and (iv) a $4.9 million decrease in distributions from equity investments.
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. 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. Free cash flow decreased by $221.7 million for the year ended December 31, 2022, primarily due to (i) a $173.6 million increase in capital expenditures, (ii) a $65.4 million decrease in net cash provided by operating activities, and (iii) a $5.2 million increase in contributions to equity investments. These amounts were offset partially by a $22.5 million increase in distributions from equity investments in excess of cumulative earnings.
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.
See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

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GENERAL TRENDS AND OUTLOOK

We expect our business 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 2020, oil and natural-gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine. For example, NYMEX West Texas Intermediate crude-oil daily settlement 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, and prices during the year ended December 31, 2022, ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022. The extent and duration of the recent commodity-price volatility cannot be predicted.
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 or increase 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, any capacity constraints, and the availability of downstream-takeaway alternatives. In some cases, we take ownership of volumes at the tailgate of our plants based on certain contractual arrangements with our producer customers, which introduces additional commodity-price exposure. 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. In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions. 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 not uncommon. 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 and in connection with the war in Ukraine. 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. Continued inflation has raised our costs for labor, materials, fuel, and services, which has increased our operating costs and capital expenditures. Increases in inflationary pressure could 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.
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Impact of interest rates. Overall, short- and long-term interest rates increased during 2021 and have continued to increase during 2022, resulting in increased interest expense on RCF borrowings and the Floating-Rate Senior Notes. Any future increases in interest rates likely will result in additional increases 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.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity as of December 31, 2022, 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 fund equity or 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) 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 2022 of $0.50000 per unit, or $196.6 million in the aggregate. The cash distribution was paid on February 13, 2023, to our unitholders of record at the close of business on February 1, 2023.
To facilitate the distribution of available cash, during 2022 we adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the regular first-quarter distribution of the following year (beginning in 2023), in a target amount equal to Free cash flow generated in the prior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases. This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of our business, and is also contingent on the attainment of prior year-end net leverage levels (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing twelve months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect. Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7.
In February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024. In November 2022, the Board authorized an increase in the program to $1.25 billion. 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. During the year ended December 31, 2022, we repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased
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from Occidental, for an aggregate purchase price of $487.6 million. The units were canceled immediately upon receipt. As of December 31, 2022, we had an authorized amount of $762.4 million remaining under the program.
For the year ended December 31, 2023, we estimate that our total capital expenditures will be between $575.0 million to $675.0 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 equity requirements 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, 2022, we had a $3.4 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 Floating-Rate Senior Notes being classified as short-term debt on the consolidated balance sheet as of December 31, 2022. As of December 31, 2022, there was $1.6 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.

Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include 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,
thousands202220212020
Acquisitions$40,127 $— $— 
Capital expenditures (1)
487,228 313,674 423,602 
Capital incurred (1)
534,342 324,150 307,644 
_________________________________________________________________________________________
(1)For the years ended December 31, 2022, 2021, and 2020, included $5.6 million, $3.6 million, and $4.8 million, respectively, of capitalized interest.

Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures within this Item 7).
Capital expenditures increased by $173.6 million for the year ended December 31, 2022, primarily due to increases of (i) $119.9 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III, and pipeline projects, (ii) $31.8 million at the DBM water systems due to construction of additional water-disposal wells and facilities and pipeline projects, and (iii) $17.3 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects. These increases were offset partially by a decrease of $8.9 million at the DJ Basin oil system, primarily related to a decrease in pipeline projects.

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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.

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,
thousands202220212020
Net cash provided by (used in):
Operating activities$1,701,426 $1,766,852 $1,637,418 
Investing activities(218,237)(257,538)(448,254)
Financing activities(1,398,532)(1,752,237)(844,204)
Net increase (decrease) in cash and cash equivalents$84,657 $(242,923)$344,960 

Operating activities. Net cash provided by operating activities decreased for the year ended December 31, 2022, primarily due to (i) the impact of changes in assets and liabilities and (ii) lower distributions from equity investments. These decreases were partially offset by (i) higher cash operating income and (ii) lower interest expense. 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. 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, 2022, primarily included the following:

•$487.2 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;

•$40.1 million of cash paid for the acquisition of the remaining 50% interest in Ranch Westex;

•$9.6 million of capital contributions primarily paid to Red Bluff Express;

•$9.5 million of increases to materials and supplies inventory;

•$263.0 million in proceeds from the sale of our 15.00% interest in Cactus II; and

•$63.9 million of distributions received from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2021, primarily 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;

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•$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.

Financing activities. Net cash used in financing activities for the year ended December 31, 2022, primarily included the following:

•$1,015.0 million of repayments of outstanding borrowings under the RCF;

•$735.8 million of distributions paid to WES unitholders;

•$502.2 million to redeem the total principal amount outstanding of WES Operating’s 4.000% Senior Notes due 2022;

•$487.6 million of unit repurchases;

•$24.9 million of distributions paid to the noncontrolling interest owner of WES Operating;

•$10.7 million of distributions paid to the noncontrolling interest owner of Chipeta;

•$1,390.0 million of borrowings under the RCF, which were used for general partnership purposes and to redeem portions of certain of WES Operating’s senior notes; and

•$2.2 million of increases in outstanding checks.

Net cash used in financing activities for the year ended December 31, 2021, primarily 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;

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•$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;

•$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;

•$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.

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Debt and credit facilities. As of December 31, 2022, the carrying value of outstanding debt was $6.8 billion and we have estimated future interest and RCF fee payments totaling $325.0 million in 2023. 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 3.790%, 4.671%, and 5.869%, respectively, at December 31, 2022. The interest rate on the Floating-Rate Senior Notes was 5.04% at December 31, 2022. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-” and in March 2022, Moody’s upgraded WES Operating’s long-term debt from “Ba2” to “Ba1.” As a result of these upgrades, annualized borrowing costs decreased by $15.7 million.
During the second quarter of 2022, WES Operating (i) redeemed the total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value and (ii) purchased and retired $1.4 million of the 3.100% Senior Notes due 2025 via open-market repurchases.
As of December 31, 2022, the Floating-Rate Senior Notes were classified as short-term debt on the consolidated balance sheet, and in January 2023, WES Operating redeemed the total principal amount outstanding at par value with cash on hand. As of December 31, 2022, 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. In June 2022, WES Operating entered into an amendment to its $2.0 billion RCF, which is expandable to a maximum of $2.5 billion, to, among other things, (i) extend the maturity date applicable to the loans and commitments of certain lenders totaling $1.6 billion to February 2026, (ii) provide for the ability of WES Operating to extend the maturity date by one year on up to two additional occasions, (iii) provide that loans under the RCF with a fixed interest rate for a specified period bear interest based on SOFR instead of LIBOR, and (iv) include an additional level of pricing if WES Operating’s senior unsecured debt rating is less than or equal to BB/Ba2/BB (S&P / Moody’s Investors Service / Fitch Ratings). The non-extending lender’s commitments mature in February 2025 and represent $400.0 million out of $2.0 billion of total commitments from all lenders.
The RCF bears interest at an Adjusted Term SOFR (as defined in the RCF amendment), plus applicable margins ranging from 1.00% to 1.70%, 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) Adjusted Term SOFR for a one-month tenor in effect on such day plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.70%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.300% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.
As of December 31, 2022, there were $375.0 million of outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $1.6 billion of available borrowing capacity under the RCF. As of December 31, 2022, the interest rate on any outstanding RCF borrowings was 5.92% and the facility-fee rate was 0.25%. As of December 31, 2022, the outstanding borrowings under the RCF were classified as long-term debt on the consolidated balance sheet and WES Operating was in compliance with all covenants under the RCF.
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.

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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, 2022, we have future finance-lease payments of $2.7 million in 2023 and a total of $5.3 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, 2022, we expect to incur asset retirement costs of $10.5 million in 2023 and a total of $290.0 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, field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors. As of December 31, 2022, we have future operating-lease payments of $10.5 million in 2023 and a total of $41.7 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, 2022, we have estimated future minimum-volume-commitment fees of $3.7 million in 2023 and a total of $7.4 million in years thereafter.

Offload commitments. During the year ended December 31, 2022, we entered into offload agreements with third parties providing firm-processing capacity through 2025. As of December 31, 2022, we have future minimum payments under offload agreements totaling $16.8 million in 2023 and a total of $10.5 million in years thereafter.

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- or NGLs-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.

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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,
thousands202220212020
Net income (loss) attributable to WES$1,217,103 $916,292 $527,012 
Limited partner interest in WES Operating not held by WES (1)
24,899 18,765 10,830 
General and administrative expenses (2)
2,656 2,932 3,552 
Other income (expense), net(45)(11)(17)
Income taxes7 9 — 
Net income (loss) attributable to WES Operating$1,244,620 $937,987 $541,377 
_________________________________________________________________________________________
(1)Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented.
(2)Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

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,
thousands202220212020
WES net cash provided by operating activities$1,701,426 $1,766,852 $1,637,418 
General and administrative expenses (1)
2,656 2,932 3,552 
Non-cash equity-based compensation expense
(570)6,912 (7,858)
Changes in working capital(9,341)(11,315)7,556 
Other income (expense), net(45)(11)(17)
Income taxes7 9 — 
WES Operating net cash provided by operating activities$1,694,133 $1,765,379 $1,640,651 
WES net cash provided by (used in) financing activities$(1,398,532)$(1,752,237)$(844,204)
Distributions to WES unitholders (2)
735,755 533,758 695,834 
Distributions to WES from WES Operating (3)
(1,219,635)(734,034)(756,112)
Increase (decrease) in outstanding checks103 (68)(35)
Unit repurchases487,590 217,465 32,535 
Other9,326 4,336 — 
WES Operating net cash provided by (used in) financing activities$(1,385,393)$(1,730,780)$(871,982)
_________________________________________________________________________________________
(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.

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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.

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.

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. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, 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 $20.6 million, $30.5 million, and $203.9 million (all of which include an other-than-temporary impairment expense of an equity investment) for the years ended December 31, 2022, 2021, and 2020, respectively. See Note 9—Property, Plant, and Equipment and Note 7—Equity Investments 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, 2022, 2021, and 2020.

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. 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, 2022, 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 and NGLs 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 and NGLs 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 and NGLs volumes owed to or by us are valued at our weighted-average cost 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 made no changes to its target range for the federal funds rate in 2021 and increased its target range seven times during the year ended December 31, 2022. Any future increases in the federal funds rate likely will result in an increase in financing costs. As of December 31, 2022, we had (i) $375.0 million of outstanding borrowings under the RCF that bear interest at a rate based on SOFR or an alternative base rate at WES Operating’s option, and (ii) the Floating-Rate Senior Notes (repaid in January 2023) 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 at December 31, 2022, it would impact the fair value of the senior notes. In addition, the transition from LIBOR to SOFR 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 paper 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, 2022. 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, 2022.
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, 2022.

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

February 22, 2023


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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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022, 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 22, 2023 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 22, 2023

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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, 2022, 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, 2022, 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, 2022 and 2021, 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, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated February 22, 2023 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 22, 2023
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands except per-unit amounts202220212020
Revenues and other
Service revenues – fee based$2,602,053 $2,462,835 $2,584,323 
Service revenues – product based249,692 122,584 48,369 
Product sales399,023 290,947 138,559 
Other953 789 1,341 
Total revenues and other (1)
3,251,721 2,877,155 2,772,592 
Equity income, net – related parties183,483 204,645 226,750 
Operating expenses
Cost of product420,900 322,285 188,088 
Operation and maintenance654,566 581,300 580,874 
General and administrative194,017 195,549 155,769 
Property and other taxes78,559 64,267 68,340 
Depreciation and amortization582,365 551,629 491,086 
Long-lived asset and other impairments (2)
20,585 30,543 203,889 
Goodwill impairment— — 441,017 
Total operating expenses (3)
1,950,992 1,745,573 2,129,063 
Gain (loss) on divestiture and other, net103,676 44 8,634 
Operating income (loss)1,587,888 1,336,271 878,913 
Interest income – Anadarko note receivable— — 11,736 
Interest expense(333,939)(376,512)(380,058)
Gain (loss) on early extinguishment of debt91 (24,944)11,234 
Other income (expense), net1,603 (623)1,025 
Income (loss) before income taxes1,255,643 934,192 522,850 
Income tax expense (benefit)4,187 (9,807)5,998 
Net income (loss)1,251,456 943,999 516,852 
Net income (loss) attributable to noncontrolling interests34,353 27,707 (10,160)
Net income (loss) attributable to Western Midstream Partners, LP$1,217,103 $916,292 $527,012 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Partners, LP$1,217,103 $916,292 $527,012 
General partner interest in net (income) loss(27,541)(19,815)(11,104)
Limited partners’ interest in net income (loss) (4)
1,189,562 896,477 515,908 
Net income (loss) per common unit – basic (4)
$3.01 $2.18 $1.18 
Net income (loss) per common unit – diluted (4)
$3.00 $2.18 $1.18 
Weighted-average common units outstanding – basic (4)
394,951 411,309 435,554 
Weighted-average common units outstanding – diluted (4)
396,236 412,022 435,624 
_________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.8 billion, $1.6 billion, and $1.8 billion for the years ended December 31, 2022, 2021, and 2020, respectively. See Note 6.
(2)See Note 7 and Note 9.
(3)Total operating expenses includes related-party amounts of $(18.0) million, $86.2 million, and $182.7 million for the years ended December 31, 2022, 2021, and 2020, respectively. See Note 6.
(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 units20222021
ASSETS
Current assets
Cash and cash equivalents$286,656 $201,999 
Accounts receivable, net554,263 436,513 
Other current assets59,506 46,252 
Total current assets900,425 684,764 
Property, plant, and equipment
Cost13,365,593 12,846,078 
Less accumulated depreciation4,823,993 4,333,171 
Net property, plant, and equipment8,541,600 8,512,907 
Goodwill4,783 4,783 
Other intangible assets713,075 744,742 
Equity investments944,696 1,167,187 
Other assets (1)
167,049 158,696 
Total assets (2)
$11,271,628 $11,273,079 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$360,562 $326,061 
Short-term debt
215,780 505,932 
Accrued ad valorem taxes72,875 44,955 
Accrued liabilities254,640 263,249 
Total current liabilities903,857 1,140,197 
Long-term liabilities
Long-term debt
6,569,582 6,400,616 
Deferred income taxes14,424 12,425 
Asset retirement obligations290,021 298,275 
Other liabilities385,629 325,806 
Total long-term liabilities
7,259,656 7,037,122 
Total liabilities (3)
8,163,513 8,177,319 
Equity and partners’ capital
Common units (384,070,984 and 402,993,919 units issued and outstanding at December 31, 2022 and 2021, respectively)
2,969,604 2,966,955 
General partner units (9,060,641 units issued and outstanding at December 31, 2022 and 2021)
2,105 (8,882)
Total partners’ capital2,971,709 2,958,073 
Noncontrolling interests136,406 137,687 
Total equity and partners’ capital3,108,115 3,095,760 
Total liabilities, equity, and partners’ capital$11,271,628 $11,273,079 
________________________________________________________________________________________
(1)Other assets includes $6.5 million and $9.8 million of NGLs line-fill inventory as of December 31, 2022 and 2021, respectively. Other assets also includes $60.4 million and $56.2 million of materials and supplies inventory as of December 31, 2022 and 2021, respectively.
(2)Total assets includes related-party amounts of $1.3 billion and $1.4 billion as of December 31, 2022 and 2021, respectively, which includes related-party Accounts receivable, net of $313.9 million and $180.2 million as of December 31, 2022 and 2021, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $312.3 million and $270.5 million as of December 31, 2022 and 2021, 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
thousandsCommon
Units		General Partner
Units		Noncontrolling
Interests		Total
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 (1)
(256,640)— (5,238)(261,878)
Unit repurchases (2)
(32,535)— — (32,535)
Acquisitions from related parties(3,987)— 3,987 — 
Contributions of equity-based compensation from Occidental14,604 — — 14,604 
Equity-based compensation expense7,857 — — 7,857 
Net contributions from (distributions to) related parties (3)
4,466 — 20,000 24,466 
Other465 — — 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 (2)
(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 parties8,533 — — 8,533 
Other(4,336)— — (4,336)
Balance at December 31, 2021$2,966,955 $(8,882)$137,687 $3,095,760 
Net income (loss)1,189,562 27,541 34,353 1,251,456 
Distributions to Chipeta noncontrolling interest owner— — (10,736)(10,736)
Distributions to noncontrolling interest owner of WES Operating— — (24,898)(24,898)
Distributions to Partnership unitholders(719,201)(16,554)— (735,755)
Unit repurchases (2)
(487,590)— — (487,590)
Contributions of equity-based compensation from Occidental
2,277 — — 2,277 
Equity-based compensation expense
25,506 — — 25,506 
Net contributions from (distributions to) related parties1,423 — — 1,423 
Other(9,328)— — (9,328)
Balance at December 31, 2022$2,969,604 $2,105 $136,406 $3,108,115 
_________________________________________________________________________________________
(1)See Note 6.
(2)See Note 5.
(3)Includes a one-time cash contribution Occidental made to WES Operating in January 2020 for anticipated transition costs required to establish stand-alone human resources and information technology functions.
See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202220212020
Cash flows from operating activities
Net income (loss)$1,251,456 $943,999 $516,852 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization582,365 551,629 491,086 
Long-lived asset and other impairments
20,585 30,543 203,889 
Goodwill impairment— — 441,017 
Non-cash equity-based compensation expense
27,783 27,676 22,462 
Deferred income taxes1,999 (9,770)3,296 
Accretion and amortization of long-term obligations, net
7,142 7,635 8,654 
Equity income, net – related parties(183,483)(204,645)(226,750)
Distributions from equity-investment earnings – related parties
186,153 213,516 246,637 
(Gain) loss on divestiture and other, net(103,676)(44)(8,634)
(Gain) loss on early extinguishment of debt(91)24,944 (11,234)
Cash paid to settle interest-rate swaps— — (25,621)
Other510 260 193 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(116,296)16,366 (193,688)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(7,812)114,887 144,437 
Change in other items, net34,791 49,856 24,822 
Net cash provided by operating activities1,701,426 1,766,852 1,637,418 
Cash flows from investing activities
Capital expenditures (1)
(487,228)(313,674)(423,602)
Acquisitions from third parties(40,127)— — 
Contributions to equity investments – related parties(9,632)(4,435)(19,388)
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Proceeds from the sale of assets to related parties200 — — 
Proceeds from the sale of assets to third parties264,121 8,102 20,333 
(Increase) decrease in materials and supplies inventory and other(9,468)11,084 (57,757)
Net cash used in investing activities(218,237)(257,538)(448,254)
Cash flows from financing activities
Borrowings, net of debt issuance costs 1,389,010 480,000 3,681,173 
Repayments of debt (1,518,548)(1,432,966)(3,803,888)
Increase (decrease) in outstanding checks2,206 (21,631)20,699 
Distributions to Partnership unitholders (1)
(735,755)(533,758)(695,834)
Distributions to Chipeta noncontrolling interest owner(10,736)(9,117)(8,644)
Distributions to noncontrolling interest owner of WES Operating(24,898)(14,984)(15,434)
Net contributions from (distributions to) related parties1,423 8,533 24,466 
Unit repurchases (1)
(487,590)(217,465)(32,535)
Other (1)
(13,644)(10,849)(14,207)
Net cash provided by (used in) financing activities(1,398,532)(1,752,237)(844,204)
Net increase (decrease) in cash and cash equivalents84,657 (242,923)344,960 
Cash and cash equivalents at beginning of period201,999 444,922 99,962 
Cash and cash equivalents at end of period$286,656 $201,999 $444,922 
Supplemental disclosures
Non-cash unit exchange with Occidental (1)
$— $— $(261,878)
Interest paid, net of capitalized interest355,363 375,007 349,913 
Income taxes paid (reimbursements received)912 938 (384)
Accrued capital expenditures82,353 35,240 25,126 
_________________________________________________________________________________________
(1)Includes related-party amounts. See Note 6.

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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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 22, 2023
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands 202220212020
Revenues and other
Service revenues – fee based$2,602,053 $2,462,835 $2,584,323 
Service revenues – product based249,692 122,584 48,369 
Product sales399,023 290,947 138,559 
Other953 789 1,341 
Total revenues and other (1)
3,251,721 2,877,155 2,772,592 
Equity income, net – related parties183,483 204,645 226,750 
Operating expenses
Cost of product420,900 322,285 188,088 
Operation and maintenance654,566 581,300 580,874 
General and administrative191,361 192,617 152,217 
Property and other taxes78,559 64,267 68,340 
Depreciation and amortization582,365 551,629 491,086 
Long-lived asset and other impairments (2)
20,585 30,543 203,889 
Goodwill impairment— — 441,017 
Total operating expenses (3)
1,948,336 1,742,641 2,125,511 
Gain (loss) on divestiture and other, net103,676 44 8,634 
Operating income (loss)1,590,544 1,339,203 882,465 
Interest income – Anadarko note receivable— — 11,736 
Interest expense(333,939)(376,512)(380,058)
Gain (loss) on early extinguishment of debt91 (24,944)11,234 
Other income (expense), net1,558 (634)1,008 
Income (loss) before income taxes1,258,254 937,113 526,385 
Income tax expense (benefit)4,180 (9,816)5,998 
Net income (loss)1,254,074 946,929 520,387 
Net income (loss) attributable to noncontrolling interest9,454 8,942 (20,990)
Net income (loss) attributable to Western Midstream Operating, LP$1,244,620 $937,987 $541,377 
________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.8 billion, $1.6 billion, and $1.8 billion for the years ended December 31, 2022, 2021, and 2020, respectively. See Note 6.
(2)See Note 7 and Note 9.
(3)Total operating expenses includes related-party amounts of $(15.0) million, $89.0 million, and $184.0 million for the years ended December 31, 2022, 2021, and 2020, respectively. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20222021
ASSETS
Current assets
Cash and cash equivalents$286,101 $195,598 
Accounts receivable, net554,263 436,513 
Other current assets57,291 44,421 
Total current assets897,655 676,532 
Property, plant, and equipment
Cost13,365,593 12,846,078 
Less accumulated depreciation4,823,993 4,333,171 
Net property, plant, and equipment8,541,600 8,512,907 
Goodwill4,783 4,783 
Other intangible assets713,075 744,742 
Equity investments944,696 1,167,187 
Other assets (1)
166,450 158,696 
Total assets (2)
$11,268,259 $11,264,847 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$404,468 $374,443 
Short-term debt
215,780 505,932 
Accrued ad valorem taxes72,875 44,955 
Accrued liabilities197,289 210,693 
Total current liabilities890,412 1,136,023 
Long-term liabilities
Long-term debt
6,569,582 6,400,616 
Deferred income taxes14,424 12,425 
Asset retirement obligations290,021 298,275 
Other liabilities383,713 324,842 
Total long-term liabilities
7,257,740 7,036,158 
Total liabilities (3)
8,148,152 8,172,181 
Equity and partners’ capital
Common units (318,675,578 units issued and outstanding at December 31, 2022 and 2021)
3,092,012 3,063,289 
Total partners’ capital3,092,012 3,063,289 
Noncontrolling interest28,095 29,377 
Total equity and partners’ capital3,120,107 3,092,666 
Total liabilities, equity, and partners’ capital$11,268,259 $11,264,847 
_________________________________________________________________________________________
(1)Other assets includes $6.5 million and $9.8 million of NGLs line-fill inventory as of December 31, 2022 and 2021, respectively. Other assets also includes $60.4 million and $56.2 million of materials and supplies inventory as of December 31, 2022 and 2021, respectively.
(2)Total assets includes related-party amounts of $1.3 billion and $1.4 billion as of December 31, 2022 and 2021, respectively, which includes related-party Accounts receivable, net of $313.9 million and $180.2 million as of December 31, 2022 and 2021, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $356.0 million and $318.7 million as of December 31, 2022 and 2021, 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
thousandsCommon
Units		Noncontrolling
Interest		Total
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 Occidental14,604 — 14,604 
Unit exchange with Occidental (1)
(261,878)— (261,878)
Net contributions from (distributions to) related parties (2)
24,466 — 24,466 
Other1,543 — 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 parties8,533 — 8,533 
Balance at December 31, 2021$3,063,289 $29,377 $3,092,666 
Net income (loss)1,244,620 9,454 1,254,074 
Distributions to Chipeta noncontrolling interest owner— (10,736)(10,736)
Distributions to WES Operating unitholders(1,244,533)— (1,244,533)
Contributions of equity-based compensation from Occidental
2,277 — 2,277 
Contributions of equity-based compensation from WES
24,936 — 24,936 
Net contributions from (distributions to) related parties1,423 — 1,423 
Balance at December 31, 2022$3,092,012 $28,095 $3,120,107 
_____________________________________________________________________________________
(1)See Note 5.
(2)Includes a one-time cash contribution Occidental made to WES Operating in January 2020 for anticipated transition costs required to establish stand-alone human resources and information technology functions.

See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202220212020
Cash flows from operating activities
Net income (loss)$1,254,074 $946,929 $520,387 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization582,365 551,629 491,086 
Long-lived asset and other impairments
20,585 30,543 203,889 
Goodwill impairment— — 441,017 
Non-cash equity-based compensation expense
27,213 34,588 14,604 
Deferred income taxes1,999 (9,770)3,296 
Accretion and amortization of long-term obligations, net
7,142 7,635 8,654 
Equity income, net – related parties(183,483)(204,645)(226,750)
Distributions from equity-investment earnings – related parties
186,153 213,516 246,637 
(Gain) loss on divestiture and other, net(103,676)(44)(8,634)
(Gain) loss on early extinguishment of debt(91)24,944 (11,234)
Cash paid to settle interest-rate swaps— — (25,621)
Other510 260 193 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(116,296)(28,965)(147,041)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(17,189)150,055 105,352 
Change in other items, net34,827 48,704 24,816 
Net cash provided by operating activities1,694,133 1,765,379 1,640,651 
Cash flows from investing activities
Capital expenditures (1)
(487,228)(313,674)(423,602)
Acquisitions from third parties(40,127)— — 
Contributions to equity investments – related parties(9,632)(4,435)(19,388)
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Proceeds from the sale of assets to related parties200 — — 
Proceeds from the sale of assets to third parties264,121 8,102 20,333 
(Increase) decrease in materials and supplies inventory and other(9,468)11,084 (57,757)
Net cash used in investing activities(218,237)(257,538)(448,254)
Cash flows from financing activities
Borrowings, net of debt issuance costs1,389,010 480,000 3,681,173 
Repayments of debt (1,518,548)(1,432,966)(3,803,888)
Increase (decrease) in outstanding checks2,309 (21,699)20,664 
Distributions to WES Operating unitholders (1)
(1,244,533)(749,018)(771,546)
Distributions to Chipeta noncontrolling interest owner(10,736)(9,117)(8,644)
Net contributions from (distributions to) related parties1,423 8,533 24,466 
Other(4,318)(6,513)(14,207)
Net cash provided by (used in) financing activities(1,385,393)(1,730,780)(871,982)
Net increase (decrease) in cash and cash equivalents90,503 (222,939)320,415 
Cash and cash equivalents at beginning of period195,598 418,537 98,122 
Cash and cash equivalents at end of period$286,101 $195,598 $418,537 
Supplemental disclosures
Non-cash unit exchange with Occidental (1)
$— $— $(261,878)
Interest paid, net of capitalized interest355,363 375,007 349,913 
Income taxes paid (reimbursements received)912 938 (384)
Accrued capital expenditures82,353 35,240 25,126 
________________________________________________________________________________________
(1)Includes related-party amounts. See Note 6.
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, 2022, 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
25 3 — 3 
NGLs pipelines2 — — 5 
Natural-gas pipelines
6 — — 1 
Crude-oil pipelines
3 1 — 3 
_________________________________________________________________________________________
(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 (see Note 3 and Note 7):
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 %
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 %
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, and (v) transactions between the Partnership and WES Operating that eliminate upon consolidation.
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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, 2022 (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. 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% limited partner interest in WES Operating owned by an Occidental subsidiary. WES Operating’s noncontrolling interest in the consolidated financial statements consists of the 25% third-party interest in Chipeta. See Note 5.

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, 2022, 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, 2022 and 2021.

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, 2022, imbalance receivables and payables were $32.7 million and $32.5 million, respectively. As of December 31, 2021, imbalance receivables and payables were $25.3 million and $16.6 million, respectively. Net changes in imbalance receivables and payables are reported in Cost of product in the consolidated statements of operations.
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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. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, 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, 2022, 2021, and 2020.

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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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 fees that require periodic rate redeterminations based on the related facility cost of service. 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. Certain of these cost-of-service agreements also have minimum-volume-commitment demand fees and guaranteed minimum revenues, in addition to cost-of-service rates. Such contracts 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. 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 agreements, percent-of-product agreements, and certain fee-based contracts that have a fixed-recovery component 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. 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 $21.8 million, $23.7 million, and $12.5 million for the years ended December 31, 2022, 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, 2022 or 2021.

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, 2022 or 2021.

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).


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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes revenue from contracts with customers:
Year Ended December 31,
thousands202220212020
Revenue from customers
Service revenues – fee based$2,602,053 $2,283,584 $2,360,680 
Service revenues – product based249,692 122,584 48,369 
Product sales399,023 290,947 138,559 
Total revenue from customers3,250,768 2,697,1152,547,608
Revenue from other than customers
Lease revenue (1)
— 179,251 223,643 
Other953 789 1,341 
Total revenues and other$3,251,721 $2,877,155 $2,772,592 
_________________________________________________________________________________________
(1)Includes fixed- and variable-lease revenue from an operating and maintenance agreement entered into with Occidental. See Operating leases within Note 6.

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $545.0 million and $424.6 million as of December 31, 2022 and 2021, respectively.
Contract assets primarily relate to (i) accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed and (ii) revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees. The following table summarizes activity related to contract assets from contracts with customers:
Year Ended December 31,
thousands20222021
Contract assets balance at beginning of year
$22,557 $56,344 
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period(7,683)(10,380)
Additional estimated revenues recognized5,531 120 
Cumulative catch-up adjustment for change in estimated consideration2,156 (23,527)
Contract assets balance at end of year
$22,561 $22,557 
December 31,
thousands20222021
Other current assets$3,381 $5,307 
Other assets19,180 17,250 
Total contract assets from contracts with customers$22,561 $22,557 

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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract liabilities primarily relate to (i) fixed and variable fees under cost-of-service contracts that are received from customers for which revenue recognition is deferred, (ii) aid-in-construction payments received from customers that must be recognized over the expected period of customer benefit, 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,
thousands20222021
Contract liabilities balance at beginning of year
$313,146 $266,937 
Cash received or receivable, excluding revenues recognized during the period71,097 83,326 
Revenues recognized that were included in the contract liability balance at the beginning of the period(16,158)(17,265)
Cumulative catch-up adjustment for change in estimated consideration1,200 (19,852)
Contract liabilities balance at end of year
$369,285 $313,146 
December 31,
thousands20222021
Accrued liabilities$20,903 $27,763 
Other liabilities348,382 285,383 
Total contract liabilities from contracts with customers$369,285 $313,146 

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, 2022, 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
2023$1,086,712 
20241,107,224 
20251,024,386 
2026874,615 
2027784,781 
Thereafter1,825,720 
Total$6,703,438 

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3. ACQUISITIONS AND DIVESTITURES

Cactus II. In November 2022, the Partnership sold its 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. Total proceeds were received during the fourth quarter of 2022, resulting in a net gain on sale of $109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

Ranch Westex. In September 2022, the Partnership acquired the remaining 50% interest in Ranch Westex JV LLC (“Ranch Westex”) from a third party for $40.1 million. Subsequent to the acquisition, (i) the Partnership is the sole owner and operator of the asset, (ii) Ranch Westex is no longer accounted for under the equity method of accounting, and (iii) the Ranch Westex processing plant is included as part of the operations of the West Texas complex.

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.

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		Record
Date
2020
March 31$0.31100 $140,893 May 14, 2020May 1, 2020
June 300.31100 140,900 August 13, 2020July 31, 2020
September 300.31100 132,255 November 13, 2020October 30, 2020
December 310.31100 131,265 February 12, 2021February 1, 2021
2021
March 31$0.31500 $132,969 May 14, 2021April 30, 2021
June 300.31900 134,662 August 13, 2021July 30, 2021
September 300.32300 134,862 November 12, 2021November 1, 2021
December 310.32700 134,749 February 14, 2022January 31, 2022
2022
March 31$0.50000 $206,197 May 13, 2022May 2, 2022
June 300.50000 197,744 August 12, 2022August 1, 2022
September 300.50000 197,065 November 14, 2022October 31, 2022
December 310.50000 196,569 February 13, 2023February 1, 2023
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4. PARTNERSHIP DISTRIBUTIONS

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) 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.

WES Operating partnership distributions. WES Operating makes quarterly cash distributions to the Partnership and WGR Asset Holding Company LLC (“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
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
2022
March 31$213,513 May 2022
June 30213,513 August 2022
September 30213,513 November 2022
December 31213,513 February 2023

In addition to the distributions above, during the years ended December 31, 2022 and 2021, WES Operating made distributions of $463.8 million and $204.1 million, respectively, to the Partnership and WGRAH. The Partnership used its portion of the distribution to repurchase common units. See Note 5.
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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, 2022, Occidental held 190,281,578 common units, representing a 48.4% 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 2.3% general partner interest in the Partnership. The public held 193,789,406 common units, representing a 49.3% 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.

Partnership equity repurchases. In February 2022, the Board authorized the Partnership to buy back up to $1.0 billion of the Partnership’s common units through December 31, 2024. In November 2022, the Board authorized an increase in the program to $1.25 billion (the “$1.25 billion Purchase Program”). The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. During the year ended December 31, 2022, the Partnership repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased from Occidental, for an aggregate purchase price of $487.6 million. The units were canceled immediately upon receipt. As of December 31, 2022, the Partnership had an authorized amount of $762.4 million remaining under the program.
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 “$250.0 million 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, 2022, (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).

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.
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5. EQUITY AND PARTNERS’ CAPITAL

The following table provides a reconciliation between basic and diluted net income (loss) per common unit:
Year Ended December 31,
thousands except per-unit amounts202220212020
Net income (loss)
Limited partners’ interest in net income (loss)$1,189,562 $896,477 $515,908 
Weighted-average common units outstanding
Basic394,951 411,309 435,554 
Dilutive effect of non-vested phantom units1,285 713 70 
Diluted396,236 412,022 435,624 
Excluded due to anti-dilutive effect554 589 997 
Net income (loss) per common unit
Basic$3.01 $2.18 $1.18 
Diluted$3.00 $2.18 $1.18 

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.

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,
thousands202220212020
Revenues and other
Service revenues – fee based$1,674,959 $1,589,367 $1,740,999 
Service revenues – product based56,907 11,888 8,509 
Product sales63,367 31,103 71,104 
Total revenues and other1,795,233 1,632,358 1,820,612 
Equity income, net – related parties (1)
183,483 204,645 226,750 
Operating expenses
Cost of product (2)
(25,447)42,805 92,884 
Operation and maintenance5,081 27,805 49,533 
General and administrative (3)
2,338 15,613 40,295 
Total operating expenses(18,028)86,223 182,712 
Gain (loss) on divestiture and other, net(1,756)420 (2,870)
Interest income – Anadarko note receivable— — 11,736 
_________________________________________________________________________________________
(1)See Note 7.
(2)Includes related-party natural-gas and NGLs imbalances.
(3)Includes 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). Balances for the years ended December 31, 2021 and 2020, also include amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6).
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6. RELATED-PARTY TRANSACTIONS

Consolidated balance sheets
December 31,
thousands20222021
Assets
Accounts receivable, net$313,937 $180,205 
Other current assets1,578 12,490 
Equity investments (1)
944,696 1,167,187 
Other assets29,058 45,494 
Total assets1,289,269 1,405,376 
Liabilities
Accounts and imbalance payables32,150 49,242 
Accrued liabilities11,756 13,914 
Other liabilities268,399 207,365 
Total liabilities312,305 270,521 
_________________________________________________________________________________________
(1)See Note 7.

Consolidated statements of cash flows
Year Ended December 31,
thousands202220212020
Distributions from equity-investment earnings – related parties
$186,153 $213,516 $246,637 
Capital expenditures(470)(2,000)— 
Contributions to equity investments – related parties(9,632)(4,435)(19,388)
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Distributions to Partnership unitholders (1)
(372,468)(272,192)(381,949)
Distributions to WES Operating unitholders (2)
(24,898)(14,984)(15,434)
Net contributions from (distributions to) related parties1,423 8,533 24,466 
Proceeds from the sale of assets to related parties200 — — 
Finance lease payments (3)
— — (6,382)
Unit repurchases from Occidental (4)
(252,500)(50,225)— 
_________________________________________________________________________________________
(1)Represents common and general partner unit 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)Included in Other cash flows from financing activities in the consolidated statements of cash flows.
(4)Represents common units repurchased from Occidental (see Note 5).
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6. RELATED-PARTY TRANSACTIONS

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 materially from the Partnership’s consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202220212020
General and administrative (1)
$5,373 $18,365 $41,609 
_________________________________________________________________________________________
(1)Includes (i) an intercompany service fee between the Partnership and WES Operating and (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). Balances for the years ended December 31, 2021 and 2020, also include amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6).

Consolidated balance sheets
December 31,
thousands20222021
Accounts receivable, net$313,937 $180,205 
Other current assets1,487 12,490 
Other assets28,459 45,494 
Accounts and imbalance payables (1)
76,131 97,749 
Accrued liabilities11,439 13,597 
_________________________________________________________________________________________
(1)Includes balances related to transactions between the Partnership and WES Operating.

Consolidated statements of cash flows
Year Ended December 31,
thousands202220212020
Distributions to WES Operating unitholders (1)
$(1,244,533)$(749,018)$(771,546)
_________________________________________________________________________________________
(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 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 35%, 36%, and 41% for the years ended December 31, 2022, 2021, and 2020, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 89%, 89%, and 88% for the years ended December 31, 2022, 2021, and 2020, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 80%, 87%, and 87% for the years ended December 31, 2022, 2021, and 2020, respectively.
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6. RELATED-PARTY TRANSACTIONS

The Partnership is currently discussing varying interpretations of certain contractual provisions 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 discussions are 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 ended as of September 30, 2022.

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 Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K).

Marketing Transition Services Agreement. During the year ended December 31, 2020, Occidental provided marketing-related services to certain of the Partnership’s subsidiaries (the “Marketing Transition Services Agreement”). While the Partnership still has some marketing agreements with affiliates of Occidental, on January 1, 2021, the Partnership began marketing and selling substantially all of its crude oil and residue gas, and a majority of its NGLs, directly to third parties.

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 right-of-use (“ROU”) asset, included in Other assets on the consolidated balance sheets, was recognized during the first quarter of 2021. The ROU asset is being 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 provided 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.
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6. RELATED-PARTY TRANSACTIONS

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.

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”). 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 $2.3 million, $10.1 million, and $14.6 million for the years ended December 31, 2022, 2021, and 2020, respectively. These amounts are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital. As of December 31, 2022, there is no unrecognized compensation expense attributable to the Incentive Plans.

Construction reimbursement agreements and purchases and sales with 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 and sells equipment, inventory, and other miscellaneous assets from or to Occidental or its affiliates.

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.

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).

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, 2021 and 2022:

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.

thousandsBalance at December 31, 2021
Other-than-temporary
impairment
expense (1)
Equity
income, net		ContributionsDistributions
Distributions
in excess of
cumulative
earnings (2)
Acquisitions and DivestituresBalance at December 31, 2022
White Cliffs$40,753 $(19,883)$(1,086)$— $(32)$(3,657)$— $16,095 
Rendezvous22,075 — (2,582)— (677)(2,702)— 16,114 
Mont Belvieu JV96,728 — 29,475 — (29,599)(5,294)— 91,310 
TEG16,116 — 6,384 75 (6,407)(312)— 15,856 
TEP188,925 — 44,650 — (44,902)(3,986)— 184,687 
FRP196,632 — 45,841 455 (46,193)(4,019)— 192,716 
Whitethorn LLC149,690 — (3,417)281 5,223 (5,182)— 146,595 
Cactus II171,294 — 11,696 — (11,835)(18,085)(153,070)— 
Saddlehorn110,441 — 21,491 — (21,034)(6,707)— 104,191 
Panola20,044 — 2,343 — (2,212)(864)— 19,311 
Mi Vida51,763 — 11,316 — (11,113)(3,104)— 48,862 
Ranch Westex979 — 3,392 — (3,392)(8,376)7,397 — 
Red Bluff Express101,747 — 13,980 8,821 (13,980)(1,609)— 108,959 
Total$1,167,187 $(19,883)$183,483 $9,632 $(186,153)$(63,897)$(145,673)$944,696 
_________________________________________________________________________________________
(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, 2022, is $23.9 million less than the Partnership’s underlying equity in White Cliffs’ net assets. During the year ended December 31, 2022, the Partnership recognized an impairment loss of $19.9 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 $16.1 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.
The investment balance in Rendezvous at December 31, 2022, includes $23.9 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of Western Gas Resources, Inc. (“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, 2022, is $33.9 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, 2022, was $17.7 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.
In September 2022, the Partnership acquired the remaining 50% interest in Ranch Westex from a third party. Subsequent to the acquisition, the Partnership is the sole owner and operator of the asset and Ranch Westex is no longer accounted for under the equity method of accounting. See Note 3. During the years ended December 31, 2021 and 2020, the Partnership recognized impairment losses of $11.8 million and $29.4 million, respectively, that resulted from a decline in value below the carrying value, which was determined to be other than temporary in nature.
In November 2022, the Partnership sold its 15.00% interest in Cactus II to two third parties. See Note 3.
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,
thousands202220212020
Revenues$1,922,733 $1,808,791 $1,635,132 
Operating income661,779 946,299 1,045,889 
Net income661,916 945,801 1,045,076 
December 31,
thousands20222021
Current assets$293,539 $398,696 
Property, plant, and equipment, net4,278,398 5,442,565 
Other assets52,163 182,323 
Total assets$4,624,100 $6,023,584 
Current liabilities$123,897 $157,099 
Non-current liabilities17,660 24,713 
Equity4,482,543 5,841,772 
Total liabilities and equity$4,624,100 $6,023,584 

8. INCOME TAXES

The Partnership is not a taxable entity for U.S. federal income tax purposes; therefore, the federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax.
For the years ended December 31, 2022 and 2020, the variance from the federal statutory rate was primarily due to the Texas margin tax liability. 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 the Texas margin tax liability.
The components of income tax expense (benefit) are as follows:
 Year Ended December 31,
thousands202220212020
Current state income tax expense (benefit)$2,188 $(37)$2,702 
Deferred state income tax expense (benefit)1,999 (9,770)3,296 
Total income tax expense (benefit)$4,187 $(9,807)$5,998 


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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 percentages202220212020
Income (loss) before income taxes$1,255,643$934,192$522,850
Statutory tax rate— %— %— %
Tax computed at statutory rate$— $— $— 
Adjustments resulting from:
Texas margin tax expense (benefit) (1)
4,187(9,807)5,998
Income tax expense (benefit)$4,187$(9,807)$5,998
Effective tax rate— %(1)%1 %
_________________________________________________________________________________________
(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,
thousands20222021
Depreciable property$(14,114)$(12,395)
Other intangible assets(603)(486)
Other293 456 
Net long-term deferred income tax liabilities$(14,424)$(12,425)

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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 Life20222021
LandN/A$10,982 $10,955 
Gathering systems – pipelines30 years5,519,592 5,386,003 
Gathering systems – compressors15 years2,266,410 2,172,953 
Processing complexes and treating facilities25 years3,419,201 3,375,317 
Transportation pipeline and equipment
4 to 48 years
174,241 169,356 
Produced-water disposal systems
20 years932,627 882,527 
Assets under constructionN/A263,353 98,473 
Other
3 to 40 years
779,187 750,494 
Total property, plant, and equipment13,365,593 12,846,078 
Less accumulated depreciation4,823,993 4,333,171 
Net property, plant, and equipment$8,541,600 $8,512,907 

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 impairments. During the year ended December 31, 2021, the Partnership recognized a long-lived asset impairment of $14.2 million at the DJ Basin complex due to cancellation of projects.
During the year ended December 31, 2020, the Partnership recognized a long-lived asset impairment of $150.2 million 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. The remaining long-lived asset 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.
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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, 2022, indicated no further impairment. Qualitative factors also were assessed in the fourth quarter of 2022 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 20222021
Gross carrying value$979,863 $979,863 
Accumulated amortization(266,788)(235,121)
Other intangible assets$713,075 $744,742 

Amortization expense for intangible assets was $31.7 million, $31.7 million, and $33.0 million for the years ended December 31, 2022, 2021, and 2020, 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,
thousands2022202120222021
Trade receivables, net$548,859 $431,649 $548,859 $431,649 
Other receivables, net5,404 4,864 5,404 4,864 
Total accounts receivable, net$554,263 $436,513 $554,263 $436,513 

A summary of other current assets is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2022202120222021
NGLs inventory$3,797 $3,370 $3,797 $3,370 
Imbalance receivables32,658 25,309 32,658 25,309 
Prepaid insurance13,262 10,369 11,139 8,538 
Contract assets3,381 5,307 3,381 5,307 
Other6,408 1,897 6,316 1,897 
Total other current assets$59,506 $46,252 $57,291 $44,421 

A summary of accrued liabilities is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2022202120222021
Accrued interest expense$110,486 $131,177 $110,486 $131,177 
Short-term asset retirement obligations
10,493 9,934 10,493 9,934 
Short-term remediation and reclamation obligations
5,383 7,454 5,383 7,454 
Income taxes payable2,428 1,516 2,428 1,516 
Contract liabilities20,903 27,763 20,903 27,763 
Accrued payroll and benefits44,855 41,311 — 20 
Other60,092 44,094 47,596 32,829 
Total accrued liabilities$254,640 $263,249 $197,289 $210,693 


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12. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:
 Year Ended December 31,
thousands20222021
Carrying amount of asset retirement obligations at beginning of year$308,209 $280,498 
Liabilities incurred10,513 23,923 
Liabilities settled(10,115)(12,710)
Accretion expense14,474 12,664 
Revisions in estimated liabilities(22,567)3,834 
Carrying amount of asset retirement obligations at end of year$300,514 $308,209 

Revisions in estimated liabilities for the year ended December 31, 2022, primarily related to a reduction in expected settlement costs at the West Texas and Brasada complexes, as well as the DBM oil and DBM water systems, partially offset by an increase in expected settlement costs at the Red Desert, Granger, and DJ Basin complexes, and at the Highlight system.

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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, 2022December 31, 2021
thousandsPrincipalCarrying
Value
Fair
Value (1)
PrincipalCarrying
Value
Fair
Value (1)
Short-term debt
Floating-Rate Senior Notes due 2023
$213,138 $213,121 $214,823 $— $— $— 
4.000% Senior Notes due 2022
— — — 502,246 502,138 505,153 
Finance lease liabilities2,659 2,659 2,659 3,794 3,794 3,794 
Total short-term debt
$215,797 $215,780 $217,482 $506,040 $505,932 $508,947 
Long-term debt
Floating-Rate Senior Notes due 2023
$— $— $— $213,138 $212,642 $213,072 
3.100% Senior Notes due 2025
730,706 727,953 692,491 732,106 728,096 764,815 
3.950% Senior Notes due 2025
399,163 396,825 379,107 399,163 395,928 418,506 
4.650% Senior Notes due 2026
474,242 472,161 452,201 474,242 471,629 516,473 
4.500% Senior Notes due 2028
400,000 396,698 368,346 400,000 396,145 437,673 
4.750% Senior Notes due 2028
400,000 397,340 368,141 400,000 396,938 444,550 
4.050% Senior Notes due 2030
1,200,000 1,191,345 1,053,038 1,200,000 1,190,339 1,323,595 
5.450% Senior Notes due 2044
600,000 593,878 503,742 600,000 593,733 717,804 
5.300% Senior Notes due 2048
700,000 687,494 580,570 700,000 687,265 844,223 
5.500% Senior Notes due 2048
350,000 342,783 291,194 350,000 342,659 418,907 
5.250% Senior Notes due 2050
1,000,000 983,945 829,804 1,000,000 983,709 1,183,514 
RCF375,000 375,000 375,000 — — — 
Finance lease liabilities4,160 4,160 4,160 1,533 1,533 1,533 
Total long-term debt
$6,633,271 $6,569,582 $5,897,794 $6,470,182 $6,400,616 $7,284,665 
_________________________________________________________________________________________
(1)Fair value is measured using the market approach and Level-2 fair value inputs.

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13. DEBT AND INTEREST EXPENSE

Debt activity. The following table presents the debt activity for the years ended December 31, 2022 and 2021:
thousandsCarrying Value
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 
RCF borrowings1,390,000 
Repayments of RCF borrowings(1,015,000)
Repayment of 4.000% Senior Notes due 2022
(502,246)
Repayment of 3.100% Senior Notes due 2025
(1,400)
Finance lease liabilities1,493 
Other5,967 
Balance at December 31, 2022$6,785,362 

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 3.790%, 4.671%, and 5.869%, respectively, at December 31, 2022, and were 4.542%, 5.424%, and 6.629%, respectively, at December 31, 2021. The interest rate on the Floating-Rate Senior Notes was 5.04% and 1.97% at December 31, 2022 and 2021, 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 second quarter of 2022, WES Operating (i) redeemed the total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value and (ii) purchased and retired $1.4 million of the 3.100% Senior Notes due 2025 via open-market repurchases.
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. For the year ended December 31, 2021, losses of $24.9 million were recognized for the early retirement of these notes.
As of December 31, 2022, the Floating-Rate Senior Notes were classified as short-term debt on the consolidated balance sheet, and in January 2023, WES Operating redeemed the total principal amount outstanding at par value with cash on hand. As of December 31, 2022, WES Operating was in compliance with all covenants under the relevant governing indentures.

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13. DEBT AND INTEREST EXPENSE

Revolving credit facility. In June 2022, WES Operating entered into an amendment to its $2.0 billion senior unsecured revolving credit facility (“RCF”), which is expandable to a maximum of $2.5 billion, to, among other things, (i) extend the maturity date applicable to the loans and commitments of certain lenders totaling $1.6 billion to February 2026, (ii) provide for the ability of WES Operating to extend the maturity date by one year on up to two additional occasions, (iii) provide that loans under the RCF with a fixed interest rate for a specified period bear interest based on the Secured Overnight Financing Rate (“SOFR”) instead of the London Interbank Offered Rate (“LIBOR”), and (iv) include an additional level of pricing if WES Operating’s senior unsecured debt rating is less than or equal to BB/Ba2/BB (Standard and Poor’s / Moody’s Investors Service / Fitch Ratings). The non-extending lender’s commitments mature in February 2025 and represent $400.0 million out of $2.0 billion of total commitments from all lenders.
The RCF bears interest at an Adjusted Term SOFR (as defined in the RCF amendment), plus applicable margins ranging from 1.00% to 1.70%, 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) Adjusted Term SOFR for a one-month tenor in effect on such day plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.70%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.300% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.
As of December 31, 2022, there were $375.0 million of outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $1.6 billion of available borrowing capacity under the RCF. As of December 31, 2022 and 2021, the interest rate on any outstanding RCF borrowings was 5.92% and 1.60%, respectively. The facility-fee rate was 0.25% at December 31, 2022 and 2021. As of December 31, 2022, the outstanding borrowings under the RCF were classified as long-term debt on the consolidated balance sheet and 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”). 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. For the year ended December 31, 2020, WES Operating made cash payments totaling $25.6 million to settle interest rate swaps that were entered into in 2018 and 2019. These cash payments were classified as cash flows from operating activities in the consolidated statements of cash flows.

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,
thousands202220212020
Long-term and short-term debt
$(326,949)$(366,570)$(369,815)
Finance lease liabilities(414)(861)(1,516)
Commitment fees and amortization of debt-related costs(12,212)(12,705)(13,501)
Capitalized interest 5,636 3,624 4,774 
Interest expense$(333,939)$(376,512)$(380,058)

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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,
20222021
thousands except lease term and discount rateOperating LeasesFinance LeasesOperating LeasesFinance Leases
Assets
Other assets$67,087 $— $71,725 $— 
Net property, plant, and equipment— 7,402 — 5,449 
Total lease assets (1)
$67,087 $7,402 $71,725 $5,449 
Liabilities
Accrued liabilities$10,342 $— $10,558 $— 
Short-term debt— 2,659 — 3,794 
Other liabilities33,318 — 35,442 — 
Long-term debt— 4,160 — 1,533 
Total lease liabilities (1)
$43,660 $6,819 $46,000 $5,327 
Weighted-average remaining lease term (years)8682
Weighted-average discount rate (%)4.5 8.2 4.1 3.4 
________________________________________________________________________________________
(1)For the years ended December 31, 2022 and 2021, includes additions to ROU assets of $8.3 million and $44.9 million, respectively, and additions to lease liabilities of $8.3 million and $14.9 million, respectively, related to operating leases. Includes additions to ROU assets and lease liabilities of $7.1 million and $0.9 million related to finance leases for the years ended December 31, 2022 and 2021, respectively.

The following table summarizes the Partnership’s lease cost:
Year Ended December 31,
thousands202220212020
Operating lease cost$14,767 $10,753 $7,702 
Short-term lease cost38,875 37,616 43,102 
Variable lease cost5,611 2,628 (46)
Sublease income(414)(414)(414)
Finance lease cost
Amortization of ROU assets5,377 7,151 8,346 
Interest on lease liabilities414 861 1,516 
Total lease cost$64,630 $58,595 $60,206 
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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,
202220212020
thousandsOperating LeasesFinance LeasesOperating LeasesFinance LeasesOperating LeasesFinance Leases
Operating cash flows$13,616 $229 $5,805 $861 $5,750 $1,516 
Financing cash flows— 4,318 — 6,513 — 14,207 

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities at December 31, 2022:
thousandsOperating LeasesFinance Leases
2023$10,517 $2,720 
20247,877 1,424 
20255,769 3,810 
20264,450 52 
20274,332 — 
Thereafter19,289 — 
Total lease payments52,234 8,006 
Less portion representing imputed interest8,574 1,187 
Total lease liabilities$43,660 $6,819 

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 outside directors, executive officers, and employees under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “2017 LTIP”) and the Western Midstream Partners, LP 2021 Long-Term Incentive Plan (the “2021 LTIP”). These plans are collectively referred to as the “WES LTIPs.” The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 9,500,000 units, respectively, of which 1,928,415 and 9,500,000 units, respectively, remained available for future issuance as of December 31, 2022. The Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan expired during the year ended December 31, 2022.
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-based 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, 2022, 2021, and 2020, the Partnership issued 13,754, 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 and 2022 pay distribution equivalents in cash ratably. The TUR and ROA Awards granted in 2021 and 2022 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 outside 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 outside 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 based on the observable market price of the Partnership’s units on the grant date of the award and compensation expense is adjusted quarterly based on the estimated performance rating at vesting. The total fair value of phantom units vested was $21.7 million, $8.5 million, and $0.5 million for the years ended December 31, 2022, 2021, and 2020, respectively, based on the market price at the vesting date. Compensation expense for the WES LTIPs was $25.5 million, $17.6 million, and $7.9 million for the years ended December 31, 2022, 2021, and 2020, respectively. As of December 31, 2022, the Partnership had $27.8 million of estimated unrecognized compensation expense attributable to the WES LTIPs that will be recognized over a weighted-average period of 0.8 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, 2022, 2021, and 2020:
202220212020
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$16.97 1,775,672 $15.69 1,307,606 $— — 
Granted26.11 866,900 17.86 1,041,635 15.49 1,442,821 
Vested16.84 (793,367)14.82 (497,648)9.54 (53,551)
Forfeited21.12 (160,175)16.83 (75,921)16.27 (81,664)
Non-vested units at end of year21.33 1,689,030 16.97 1,775,672 15.69 1,307,606 

The following table summarizes TUR Awards activity under the WES LTIPs for the years ended December 31, 2022, 2021, and 2020:
202220212020
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$21.17 325,217 $17.79 108,481 $— — 
Granted37.80 94,173 22.77 237,720 17.79 124,067 
Forfeited28.54 (30,573)21.78 (20,984)17.79 (15,586)
Non-vested units at end of year24.62 388,817 21.17 325,217 17.79 108,481 

The following table summarizes ROA Awards activity under the WES LTIPs for the years ended December 31, 2022, 2021, and 2020:
202220212020
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$16.01 325,217 $16.27 108,481 $— — 
Granted25.95 94,173 15.88 237,720 16.27 124,067 
Forfeited19.74 (30,573)15.96 (20,984)16.27 (15,586)
Non-vested units at end of year18.12 388,817 16.01 325,217 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, 2022 and 2021, the consolidated balance sheets included $7.4 million and $10.1 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 year.
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 and offload 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 oil system, DBM water systems, and DJ Basin complex.

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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, 2022.

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, 2022, 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, four 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. Oscar K. Brown, 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. In determining Mr. Brown’s independence, the Board considered the fact that his spouse is a partner at a law firm that WES has used from time to time.

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 Chairperson and Chief Executive Officer (“CEO”), our general partner’s limited liability company agreement and Corporate Governance Guidelines permit the roles of Chairperson and CEO to be combined. Thus, while those roles currently are separated, 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 16, 2023.
NameAgePosition with Western Midstream Holdings, LLC
Peter J. Bennett55Chairperson of the Board
Michael P. Ure46President, Chief Executive Officer, and Director
Kristen S. Shults38Senior Vice President and Chief Financial Officer
Robert W. Bourne67Senior Vice President and Chief Commercial Officer
Christopher B. Dial46Senior Vice President, General Counsel and Secretary
Michael S. Forsyth57Senior Vice President, North Operations
Catherine A. Green49Senior Vice President and Chief Accounting Officer
Daniel P. Holderman43Senior Vice President, South Operations
Oscar K. Brown52Director
Nicole E. Clark 53Director
Frederick A. Forthuber 59Director
Kenneth F. Owen 49Director
David J. Schulte 61Director
Lisa A. Stewart 65Director

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 Chairperson 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.
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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. Mr. Ure also served as interim Chief Financial Officer of our general partner from September 2020 to May 2022. 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.
Kristen S. Shults
Houston, Texas
Officer since:
May 2022
Biography/Qualifications
 
Ms. Shults has served as Senior Vice President and Chief Financial Officer of our general partner since May 2022, as Senior Vice President, Finance and Communications of our general partner since May 2021, and as Vice President, Investor Relations and Communications of our general partner since November 2019. Ms. Shults joined Anadarko in 2015 and has over 12 years of experience in the oil and gas industry. During her career at Anadarko, Ms. Shults served in various roles of increasing responsibility throughout Anadarko’s tax organization, including Director of Tax Compliance and Reporting from March 2018 to November 2019 and Worldwide Tax Manager from February 2017 to February 2018. Ms. Shults began her career in the tax practice of Ernst & Young, LLP, and is a Certified Public Accountant.
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 32 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.
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.
Michael S. Forsyth
Denver, Colorado
Officer since:
October 2022
Biography/Qualifications
 
Mr. Forsyth has served as Senior Vice President, North Operations, of the general partner since October 2022 and as Vice President, Engineering for Western Midstream Operating, LP, a consolidated subsidiary of WES, since November 2019. Mr. Forsyth joined Anadarko in 2005 and has over 30 years of experience in the energy industry. During his career at Anadarko, Mr. Forsyth served in various roles of increasing responsibility throughout Anadarko’s midstream engineering organization, including General Manager, Midstream Asset Planning from February 2018 to November 2019 and as General Manager, Infrastructure Planning from April 2017 to February 2018. Prior to joining Anadarko, Mr. Forsyth served in engineering and project management roles at various construction and engineering firms.
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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 served in a variety of diverse roles throughout the accounting and finance organization, including internal audit, technical U.S. GAAP accounting, internal controls, and as Director, Expenditure Accounting from March 2018 to September 2019. Prior to joining Anadarko, Ms. Green began her career as an auditor with Grant Thornton LLP in the United Kingdom and Houston and is a Chartered Accountant with the Institute of Chartered Accountants in England and Wales.
Daniel P. Holderman
Houston, Texas
Officer since:
August 2022
Biography/Qualifications
 
Mr. Holderman has served as Senior Vice President, South Operations, of the general partner since October 2022 and served as Senior Vice President and Co-Chief Operating Officer of the general partner from August 2022 to October 2022. Before joining WES, Mr. Holderman served as Director, Delaware Basin Asset for Oxy USA, Inc., a subsidiary of Occidental, assuming the role in November 2018. Previously, Mr. Holderman had served as the Asset Manager overseeing Occidental’s Midland Basin assets in West Texas, assuming that role in June 2017. Mr. Holderman joined Occidental in December 2013, and held various engineering and operations leadership roles across drilling, completions, and production operations. Prior to joining Occidental, Mr. Holderman had nine years of experience in engineering, upstream operations, and commercial roles with ExxonMobil.
Oscar K. Brown
Houston, Texas
Director since:
August 2019
Independent
Biography/Qualifications

Mr. Brown has served as a member of our Board since August 2019, as Chairperson of the ESG Committee since February 2021, and as a member of the Compensation Committee since February 2022. Since April 2022, Mr. Brown has also served as Chief Financial Officer of FREYR Battery, which provides industrial scale clean battery solutions to reduce global emissions. Mr. Brown previously 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 also 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.
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 ESG Committee since February 2021, and as a member of the 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 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. Mr. Forthuber has more than 37 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.
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Kenneth F. Owen
Houston, Texas
Director since:
September 2020
Independent
Biography/Qualifications
 
Mr. Owen has served as a member of our Board, Chairperson of the Audit Committee, and a member of the Special Committee 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.
David J. Schulte
Kansas City, Missouri
Director since:
September 2020
Independent
Biography/Qualifications
 
Mr. Schulte has served as a member of our Board, Chairperson of the Special Committee, and a member of the Audit Committee 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, and as a member of the Audit Committee and Special Committee, since September 2020, and as Chairperson of the Compensation Committee since February 2022. Ms. Stewart serves as Sheridan Production Partners Executive Chairwoman, a position she has held since April 2020. From the founding of Sheridan in 2006, she served as Chairwoman, 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 41 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 a 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. On December 31, 2019, WES entered into an amended and restated Services Agreement, under which we reimbursed Occidental for administrative services it performed on our behalf through December 31, 2020, with the agreement renewing every six months thereafter for so long as not terminated by either party. 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 (Chairperson) 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 5 meetings during 2022.
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 (Chairperson) 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.

ESG Committee. The ESG Committee is comprised of one independent director, Mr. Brown (Chairperson), and two non-independent directors, Mr. 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.

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 two independent directors, Ms. Stewart (Chairperson) and Mr. Brown, and two non-independent directors, Ms. Clark and Mr. Bennett. The Compensation Committee held 3 meetings during 2022.
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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our Board, all of our non-management directors meet in an executive session without management participation. 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.

Director Attendance

The Board of Directors held five meetings in 2022. Each of the directors attended 100% of the aggregate number of regularly scheduled meetings of the Board and of the Board committees on which he or she served and which were held during the period that each director served.

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”) provides a description of the material elements, objectives, and principles of WES’s 2022 executive compensation program for its named executive officers (“NEOs”), recent compensation decisions, and the factors the Compensation Committee and the Board considered in making those decisions.

2022 Named Executive Officers

wes-20221231_g11.jpg
wes-20221231_g12.jpg
wes-20221231_g13.jpg
wes-20221231_g14.jpg
wes-20221231_g15.jpg
Michael P. Ure
President and
Chief Executive Officer
Kristen S. Shults
Senior Vice President and Chief Financial Officer
Robert W. Bourne
Senior Vice President and Chief Commercial Officer
Christopher B. Dial
Senior Vice President, General Counsel and Secretary
Catherine A. Green
Senior Vice President and Chief Accounting Officer

Ms. Shults was promoted to Senior Vice President and Chief Financial Officer (“CFO”) on May 2, 2022. In addition, Mr. Craig W. Collins, Former Senior Vice President and Co-Chief Operating Officer, was a named executive officer for 2022.

Executive Summary

Now that WES has substantially completed our strategic shift toward becoming a functionally independent company, we have turned our focus to creating value for WES unitholders through cost efficiencies, increasing the quality, safety, and reliability of WES’s service offerings, and a balanced approach to distributions, debt reduction, and common unit repurchases. Our compensation program is designed to align the interests of our executive officers with those of our unitholders by providing pay that is linked to the achievement of performance goals established to foster the creation of sustainable, long-term value for WES.

In 2022, our Board took the following key actions related to executive compensation:

•Established a Compensation Committee to assist the Board in making compensation decisions related to our executive officers and non-employee directors;

•Conducted an annual review of compensation for our executive officers and made changes to their base salaries, target bonus opportunities, and long-term incentive awards;

•Upon hiring of Daniel Holderman as Senior Vice President and Co-Chief Operating Officer, reviewed and approved his compensation package;

•Upon Ms. Shults’s appointment to CFO in May 2022, reviewed and approved changes to her compensation in order to reflect her new role and responsibilities;

•Following the appointment of Michael Forsyth as Senior Vice President, North Operations, reviewed and approved changes to his compensation in order to reflect his new role and responsibilities; and

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•Reviewed our annual cash incentive program and updated the performance metrics to incorporate additional ESG metrics related to methane reduction and the development of greenhouse gas tracking and reporting processes.

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 our executive officers’ interest with those of our long-term unitholders.

2022 Business and Performance Highlights

2022 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 2022 fiscal year WES:

•Grew average throughput for natural-gas, crude-oil and NGLs, and produced-water by 1-percent, 3-percent and 19-percent year-over-year, respectively.

•Completed 39-percent of the $1.25 billion unit repurchase program by repurchasing 19,532,305 units for aggregate consideration of $487.6 million through year end 2022.

•Achieved year-end 2022 net leverage ratio of approximately 3.1 times, which surpasses the 2022 Enhanced Distribution leverage target of 3.4 times.

•Achieved full-year cash distribution guidance of $2.00 per unit or greater.

•Established a board-level Compensation Committee.

How We Make Compensation Decisions

Our Board has responsibility for approving the officer and director compensation plans, policies, and programs of the Partnership. 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. The Compensation Committee and the Board use several resources in reviewing elements of executive compensation and making compensation decisions. These decisions are not purely formulaic, and the Compensation Committee and the Board exercise judgement and discretion as deemed appropriate.

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Compensation Philosophy and Objectives of our Compensation Program

Our Board is committed to a compensation philosophy that is designed to align the interests of our executive officers with those of our unitholders by linking compensation to the achievement of performance goals established to foster the creation of long-term value. The executive compensation program has evolved over the last several years, corresponding to the Partnership’s transition to becoming a functionally independent company with a WES-dedicated management team. As noted above, WES established the Compensation Committee in February 2022 after the 2022 executive compensation actions were determined. Since its formation, the Compensation Committee has worked with its compensation consultant to assist the Board in developing a compensation framework that aligns the interests of our executive officers with those of our unitholders through a culture of equity ownership and an executive compensation program that is more heavily weighted toward at-risk compensation. In developing WES’s executive compensation program, the Compensation Committee intends to target a total compensation package for its executive officers, including the NEOs, that generally provides for (i) median market annual base compensation, (ii) incentive-based compensation composed of short-term incentives targeted slightly above the median market (i.e., approximately the 50th-60th percentile of market), and (iii) long-term incentives that are targeted to pay out at approximately the third-quartile of market. Going forward, the Compensation Committee will utilize this compensation philosophy along with the Partnership’s performance, individual performance, and general market conditions to determine the final compensation awards for the NEOs.
The Board and the Compensation Committee believe the design of our executive compensation program, and the Compensation Committee’s decisions and outcomes in 2022, support our compensation philosophy and objectives, including:

•Annual incentive awards earned are based on achievement of specific financial, operating, safety, and strategic goals;

•Performance-based long-term incentive awards are tied to specific and formulaic financial performance and stock price growth objectives;

•Aligning compensation with unitholder interests;

•Emphasizing performance-based compensation that balances short-term and long-term results; and

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

Administration of Executive Compensation Program and Methodology

Role of the Compensation Committee. Our Compensation Committee, two members of which are independent directors, is appointed by the Board to set our compensation philosophy and objectives as well as design our executive compensation program. The Compensation Committee is responsible for, among other things, the following:

•Reviewing the design and structure of WES’s executive compensation programs to promote alignment with WES's short-term and long-term strategies and business objectives;

•Establishing parameters for the benchmarking of compensation, including reviewing and approving an appropriate peer group of companies;

•Annually reviewing the corporate goals and objectives relevant to the compensation of the executive officers and their annual base salary, annual bonus or incentive opportunity, equity-based opportunities (including time-vested and performance-based phantom units), any supplemental benefits, and any employment, severance, or change-in-control agreements, and make recommendations to the Board with respect to such items; and

•Reviewing and discussing with management the Compensation Discussion and Analysis included in WES’s Annual Report on Form 10-K, and preparing a Compensation Committee Report for inclusion in such 10-K.
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Our Compensation Best Practices. The Board and the Compensation Committee oversee the design and administration of the compensation program for our executive officers. The table below highlights the best practices utilized in the compensation process.

What We Do

ü
•Align executive officer pay with performance by structuring more than 77% of pay as at-risk
•Emphasize long-term performance in our equity incentive awards
•Provide an appropriate mix of fixed and variable pay to encourage retention and increase long-term and sustainable unitholder value
•Use appropriate peer group comparisons to determine compensation
•Maintain a compensation committee, advised by an independent compensation consultant, that makes recommendations to the Board for approval
•Require executive officers to maintain a meaningful equity ownership position via unit ownership
•Pay distributions on performance unit awards only at the end of the performance period, based on units earned
•Employ clawback provisions in our long-term equity awards
What We
Don’t Do
X
•Provide excessive perquisites or personal benefits to our executive officers
•Allow short-selling or hedging of company securities
•Excise tax gross-ups
•Guaranteed bonuses
•Automatic base salary increases

Role of the Compensation Consultant. Through July 2022, the Board retained Meridian Compensation Partners, LLC (Meridian) as its independent compensation consultant to assist the Board and the newly-formed Compensation Committee with the design of our executive compensation program for 2022. In August 2022, the Compensation Committee retained Zayla Partners (thereby replacing Meridian) as its independent compensation consultant to provide advice on various executive compensation matters. Meridian provided guidance on our benchmarking peer group, pay levels, pay mix, and overall executive compensation program design for the 2022 calendar year. Since its engagement by the Compensation Committee, Zayla Partners provided guidance with respect to our overall compensation program design for the 2023 calendar year. Throughout their respective engagements, each of the independent executive consultants reported directly to the Compensation Committee and the Board and provided no other material services to us.

Benchmarking Peers. With assistance from Meridian, the Board evaluated several factors when determining an appropriate peer group of companies to use for 2022 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 for 2022 compared to the peer group used to evaluate 2021 compensation decisions.

The Partnership’s peer group used for conducting the 2022 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.

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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 in connection with the general structuring of the officers’ compensation packages; however, the Board did not target a specific percentile of the benchmark data for the 2022 compensation decisions, and in making specific officer compensation decisions, the Board has taken into account other considerations as noted below.

Role of Executive Officers in Setting Executive Compensation. The Board, after reviewing the information provided by Meridian for 2022 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.
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2022 Annual Compensation Program

We believe that compensation for our NEOs should be competitive within our stated peer group and any rewards should be directly linked to the interests of our unitholders. Our executive compensation program includes a mix of direct and indirect compensation elements. Performance metrics for short-term and long-term incentive programs include a balance of both financial and operational targets that align with our business strategy. 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.
As illustrated in the charts below, our CEO’s target direct compensation is heavily weighted towards at-risk compensation, with 88% of our CEO’s compensation based on performance and time-based awards. In addition, 77% of our other NEOs’ target direct compensation, on average, is at-risk. Further, 72% of our CEO’s targeted annual direct compensation and 58%, 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

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The charts above are based on the following compensation elements, as discussed under Analysis of 2022 Compensation Actions: base salaries approved in 2022; 2022 target bonus opportunities; and the target value of the 2022 annual long-term incentive awards.
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Direct Compensation Elements. WES’s direct compensation program is based on three key elements of compensation: base salary, long-term incentives comprised of equity-based awards, including time-based and performance-based awards, and short-term incentive comprised of an annual cash bonus award. Each element is intended to offer a competitive compensation level relative to our peers that aids in the retention of our executives.

ElementAwardPerformance MetricsPurpose
Base SalaryCashN/AProvides a fixed level of competitive compensation based on performance, expertise, and experience 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 reward sustained financial performance by providing an incentive for NEOs to focus on efficiently managing WES’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 reward unit price performance relative to our performance peer group, provide an effective comparison of our unit price performance against an industry peer group, align the interests of our NEOs with that of our unitholders, and provide a retentive value
Annual Cash IncentivesCashAdjusted EBITDA
Free Cash Flow
System Availability
TRIR
Volunteer Participation
Methane Reduction
Greenhouse Gas		Based on the achievement of WES’s performance goals, which are aligned with key financial, operational, and sustainability metrics, the annual cash incentive provides incentives for the NEOs to focus and excel in areas aligned with WES’s short-term business objectives

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Analysis of 2022 Compensation Actions

The following is a discussion of the specific actions taken by the Board in 2022 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 Approved in 2021 ($)Salary Approved in 2022 ($)% Change
Mr. Ure725,000 775,000 6.9 %
Ms. Shults (1)
— 400,000 — 
Mr. Dial 400,000 425,000 6.3 %
Mr. Bourne405,000 425,000 4.9 %
Ms. Green (1)
— 400,000 — 
Mr. Collins (2)
475,000 510,000 7.4 %
________________________________________________________________________________________
(1)Ms. Shults and Ms. Green were not NEOs for the year 2021.
(2)Mr. Collins left WES effective November 11, 2022.

The Board approved an increase to Mr. Ure’s salary to better align his salary with the median of the peer benchmark data for the chief executive officer position. Ms. Shults did not receive a salary increase in conjunction with her appointment to CFO in May 2022. The salary increases for the other NEOs were based on internal compensation alignment considerations and to bring their salaries closer to the median of the peer benchmark data.

Equity-Based Long-term Incentive Awards. Our long-term incentive program aligns our NEOs’ interests with those of our unitholders by providing them with the opportunity to earn compensation based on WES’s success. Our Board did not make changes in 2022 to the 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. 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 58% for our other NEOs.

Time-Based Units. These units, reflecting 50% of the overall 2022 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. Our Board has determined that granting time-based units aligns the interests of our NEOs with our unitholders, provides a retention tool, and rewards long-term service.

Return on Asset Performance Units (“ROA Units”). The Board established ROA as a performance criterion for 25% of the 2022 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 paid prior to the settlement of such ROA Units 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 2022 annual long-term incentive awards. The units vest based on our TUR performance ranking relative to our peer group 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 2022 TUR awards is listed below. There were no changes in peer companies compared to the 2021 peer group.
•Antero Midstream Corporation
•Equitrans Midstream Corporation
•Crestwood Equity Partners LP
•Magellan Midstream Partners LP
•DCP Midstream LP
•Plains All American Pipeline LP
•EnLink Midstream, LLC
•Targa Resources Corporation

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 peer company 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.

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Equity Awards Granted in 2022. In 2022, the Board approved the below annual long-term incentive awards. These awards are included in the Grants of Plan-Based Awards Table. The target value of the 2022 annual equity awards granted to the NEOs, excluding Ms. Shults, reflect an increase of approximately 25%, on average, compared to their prior year target value of annual awards. In conjunction with her promotion to CFO in May 2022, Ms. Shults received a one-time promotional grant with a target value of $1,050,000 delivered in 50% time-based units, 25% TUR performance units, and 25% ROA performance units. This award was intended to align Ms. Shults’s compensation with the other NEOs by providing her a similar link to performance and to increase her equity holdings to a level consistent with the CFO role. 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. Ure4,500,000 86,705 2,250,000 43,353 1,125,000 43,353 1,125,000 
Ms. Shults (2)
1,700,000 46,533 1,175,000 10,838 262,500 10,838 262,500 
Mr. Dial900,000 17,341 450,000 8,671 225,000 8,671 225,000 
Mr. Bourne900,000 17,341 450,000 8,671 225,000 8,671 225,000 
Ms. Green650,000 12,524 325,000 6,262 162,500 6,262 162,500 
Mr. Collins (3)
1,700,000 32,755 850,000 16,378 425,000 16,378 425,000 
_________________________________________________________________________________________
(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)Ms. Shults’s values include her CFO promotional award and her 2022 annual award she received prior to her promotion to CFO. Her annual award of time-based units was granted under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.
(3)Per the terms of Mr. Collins’s award agreements, upon his departure from WES, he received a prorated portion of these awards.

Performance Unit Awards - Results for the Performance Period Ended December 31, 2022. In February 2023, the Compensation Committee recommended for certification, and the Board certified, the performance results for the 2020 annual TUR Unit and ROA Unit awards. These awards had a three-year performance period that began on January 1, 2020, and ended December 31, 2022. Under the 2020 TUR Unit awards, WES ranked 3rd in TUR relative to the established peer group, which resulted in a payout of 150%. Under the 2020 ROA Unit awards, WES achieved a three-year average ROA of 17.5%, which resulted in a payout of 163.3%. Upon the Board’s performance certification, these awards were paid in the form of WES units.
The following table lists the target number of performance units awarded and actual performance units earned by the NEOs under the 2020 annual TUR Unit and ROA Unit awards.

ROA UnitsTUR Units
Paid at 163.3% of TargetPaid at 150% of Target
NameNumber of Units - TargetNumber of Units - EarnedNumber of Units - TargetNumber of Units - Earned
Mr. Ure46,817 76,452 46,817 70,226 
Ms. Shults (1)
— — — — 
Mr. Dial9,363 15,290 9,363 14,045 
Mr. Bourne10,924 17,839 10,924 16,386 
Ms. Green3,902 6,372 3,902 5,853 
Mr. Collins (2)
19,344 31,589 19,344 29,016 
_________________________________________________________________________________________
(1)Ms. Shults was not eligible for a grant of performance units in 2020.
(2)Per the terms of Mr. Collins’s award agreements, upon his departure from WES, he received a prorated portion of these awards.

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Performance-Based Annual Cash Incentives—WES Cash Bonus Program. Our Board has approved the WES Cash Bonus Program (“WCB Program”) under our 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 2022, individual target bonus dollar values were approved by the Board for each of our NEOs as noted in the table below.
2021 Target Bonus2022 Target Bonus
Name$% of Salary$% of Salary
Mr. Ure833,750115%968,750125%
Ms. Shults (1)
——320,00080%
Mr. Dial275,00069%340,00080%
Mr. Bourne330,00081%340,00080%
Ms. Green (1)
——320,00080%
Mr. Collins (2)
475,000100%586,500115%
_________________________________________________________________________________________
(1)Ms. Shults and Ms. Green were not NEOs for the year 2021.
(2)Mr. Collins left WES effective November 11, 2022.

Changes to target bonuses for 2022 were determined based on a review of our peer benchmarking data and internal pay equity considerations. The Board did not approve a change in Ms. Shults’s target bonus opportunity at the time of her promotion to CFO.
In February 2022, 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, 2022. 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 2022 WCB Program is similar to the 2021 WCB Program, but with some changes to our environmental and safety metrics. Emphasizing our commitment to sustainability, we incorporated goals regarding methane reduction and greenhouse gas tracking and reporting processes into the Program. The addition of these two metrics to our existing Sustainability metrics of Total Recordable Incident Rate (“TRIR”) and Volunteer Participation supports our foundational pillar of sustainable operations through our commitment to the safety of our people, lowering our carbon intensity, and improving our communities.
The table below reflects the Partnership’s 2022 performance metrics, performance targets and performance under these metrics.
Performance MetricRelative Weighting FactorWCB Program
Performance
Targets		WCB Program Performance
Results
Financial
Adjusted EBITDA (1)
30%$1,975MM$2,127.9MM
Free Cash Flow (2)
30%$1,250MM$1,357.8MM
Operational
System Availability (3)
20%99%98.7%
Sustainability
TRIR (4)
9%0.300.53
Employee Volunteer Participation (5)
3%50% Participation63.4%
Methane Reduction5%5% Reduction5.8%
Greenhouse Gas (6)
3%QualitativeAchieved
100%
_________________________________________________________________________________________
(1)Adjusted EBITDA, for purposes of the WCB program, excludes the effects of revenue recognition cumulative adjustments (see Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K).
(2)Free cash flow, for purposes of the WCB program, excludes the effects of changes in working capital (see Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K).
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(3)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.
(4)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.
(5)Employee Volunteer Participation includes employee volunteer participation through a WES coordinated event focused on local nonprofit organizations or individual volunteer time through a registered 501(c)3.
(6)WES set a qualitative goal to develop a Greenhouse Gas (“GHG”) emissions management system to measure GHG emissions and identify actionable emissions-reduction projects.

2022 WCB Program Performance Assessment. In assessing the Partnership’s performance under the WCB Program, the Board considered our performance against the pre-established targets for the year. Based upon the results described above and in recognition of the overall excellent financial and operational performance, including exceptional achievement with respect to Adjusted EBITDA, Free cash flow, and WES’s methane emissions reduction goals, the Board approved a payout of 157% under the 2022 WCB Program.

Actual Bonuses Earned for 2022. The cash bonus awards for 2022 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 ($)		Board Assessment of 2022 WCB ProgramCash Bonus
Awards ($)
Mr. Ure968,750x157%=1,520,938
Ms. Shults (1)
320,000x157%=502,400
Mr. Dial340,000x157%=533,800
Mr. Bourne340,000x157%=533,800
Ms. Green320,000x157%=502,400
Mr. Collins (2)
506,158x157%=794,668
_________________________________________________________________________________________
(1)Ms. Shults was promoted to Senior Vice President and CFO May 2, 2022. The Board did not approve a change in Ms. Shults’s target bonus opportunity at the time of her promotion to CFO.
(2)Mr. Collins left WES effective November 11, 2022, and his target bonus is reflected on a pro-rata basis.

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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

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 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.

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 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. Each of our NEOs is covered by 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;

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•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;

•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.

A detailed discussion of the benefits under these plans is included in the Potential Payments Upon Termination or Change of Control section below, including a discussion of the ESP benefits payable to Mr. Collins upon his departure from the Partnership on November 11, 2022.

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 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. The Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan, under which certain outstanding awards were issued, expired in November 2022. 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.

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Equity Ownership Guidelines. In order to align the interests of executives and unitholders, the Board has 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

Clawback Provisions. Per the terms of our 2022 long-term incentive awards which were granted under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan and the Western Gas 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).

Blackout Periods. Our Insider Trading Policy prescribes regularly scheduled blackout periods for each fiscal quarter. The scheduled blackout periods begin on the last calendar day of the quarter and end two full trading days following the public release of the applicable quarter’s earnings. The blackout periods apply to all WES officers, including our NEOs, all directors of our General Partner, employees working in our Denver, Colorado and The Woodlands, Texas offices, and any other person designated by our General Counsel from time to time. These blackout restrictions also apply to the immediate family and others who live in their homes, as well as any trust, partnership, or other entity in which the covered individual controls.

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.

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Compensation Committee Report

The Compensation Committee, the members of which are listed below, is responsible for reviewing and recommending to the Board for approval actions related to the executive compensation programs of the Partnership. The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on such review and discussions, the Compensation Committee recommended to the Board that it be included in this Form 10-K.

The Compensation Committee of Western Midstream Holdings, LLC:

Lisa Stewart, Chairperson
Peter J. Bennett
Oscar K. Brown
Nicole E. Clark

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EXECUTIVE COMPENSATION

Summary Compensation Table

The following table summarizes the compensation amounts for our NEOs for the years ended December 31, 2022, 2021, and 2020.
Name and Principal PositionYearSalary
($)
Bonus
($) (1)
Stock
Awards
($) (2)
Non-Equity
Incentive Plan
Compensation
($) (3)
All Other
Compensation
($) (4)
Total
($)
Michael P. Ure2022767,308 1,520,938 5,034,558 — 325,201 7,648,005 
President and2021713,462 416,041 6,259,276 984,659 344,607 8,718,045 
Chief Executive Officer2020641,346 617,500 4,133,602 — 42,439 5,434,887 
Kristen S. Shults2022362,731 502,400 1,807,184 — 68,558 2,740,873 
Senior Vice President and
Chief Financial Officer
Christopher B. Dial (5)
2022421,154 533,800 1,006,937 — 123,641 2,085,532 
Senior Vice President,2021388,462 137,225 1,459,424 324,775 100,514 2,410,400 
General Counsel and Secretary
Robert W. Bourne2022421,923 533,800 1,006,937 — 165,975 2,128,635 
Senior Vice President and2021405,000 164,670 1,201,841 389,730 181,082 2,342,323 
Chief Commercial Officer2020417,692 313,500 981,448 — 41,725 1,754,365 
Catherine A. Green (6)
2022384,616 902,400 727,206 — 144,897 2,159,119 
Senior Vice President and
Chief Accounting Officer
Craig W. Collins (7)
2022445,769 794,668 1,901,951 — 1,906,098 5,048,486 
Former Senior Vice President and2021471,923 237,025 2,575,436 560,975 204,045 4,049,404 
Chief Operating Officer2020461,923 370,500 1,757,410 — 41,500 2,631,333 
_________________________________________________________________________________________
(1)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.
(2)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 2022 ROA unit awards as of the grant date for Mr. Ure, Ms. Shults, Mr. Dial, Mr. Bourne, Ms. Green, and Mr. Collins were approximately $2.3 million, $0.52 million, $0.45 million, $0.45 million, $0.32 million, and $0.85 million, respectively. The maximum values, assuming a 200% payout, of the 2022 TUR unit awards as of the grant date for Mr. Ure, Ms. Shults, Mr. Dial, Mr. Bourne, Ms. Green, and Mr. Collins were approximately $3.3 million, $0.74 million, $0.66 million, $0.66 million, $0.48 million, and $1.3 million, respectively. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For a discussion of valuation assumptions for the awards, 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 2022, see the Grants of Plan-Based Awards in 2022 table.
(3)This column reflects the portion of the annual cash bonus awards calculated based on our unadjusted performance results, pursuant to the WCB Program.

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(4)The 2022 amounts are detailed in the table below:
NamePayments by the Partnership to Employee 401(k) Plan and Savings Restoration Plan ($)
Other ($) (i)
Total ($)
Michael P. Ure325,201 — 325,201 
Kristin S. Shults (5)
68,558 — 68,558 
Christopher B. Dial (5)
123,641 — 123,641 
Robert W. Bourne165,975 — 165,975 
Catherine A. Green (5)
144,897 — 144,897 
Craig W. Collins (6)
186,565 1,719,533 1,906,098 
________________________________________________________________
(i)    For Mr. Collins, the amount includes benefits payable under the Executive Severance Plan in the amount of $1,644,750 and the payout upon his termination of his accrued but unused paid time off balance of $74,783.
(5)Ms. Shults and Ms. Green were not NEOs for the years ended December 31, 2021 and 2020. Mr. Dial was not an NEO for the year ended December 31, 2020.
(6)Includes a $400,000 retention bonus for which restrictions lapsed during 2022.
(7)Mr. Collins left WES effective November 11, 2022.

Grants of Plan-Based Awards in 2022

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 2012 Long-Term Incentive Plan and the Western Gas Partners, LP 2017 Long-Term Incentive Plan during 2022 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, 2024. 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, 2023. 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— — 968,750 — — — — — — 
Time-Based Units02/15/2022— — — — — — 86,705 2,249,995 
ROA Units02/15/2022— — — 10,838 43,353 86,706 — 1,125,010 
TUR Units02/15/2022— — — 10,838 43,353 86,706 — 1,659,553 
Kristen S. Shults (3)
— — 320,000 — — — — — — 
Time-Based Units02/15/2022— — — — — — 24,857 650,011 
Time-Based Units05/02/2022— — — — — — 21,676 524,993 
ROA Units05/02/2022— — — 2,710 10,838 21,676 — 262,496 
TUR Units05/02/2022— — — 2,710 10,838 21,676 — 369,684 
Christopher B. Dial— — 340,000 — — — — — — 
Time-Based Units02/15/2022— — — — — — 17,341 449,999 
ROA Units02/15/2022— — — 2,168 8,671 17,342 — 225,012 
TUR Units02/15/2022— — — 2,168 8,671 17,342 — 331,926 
Robert W. Bourne— — 340,000 — — — — — — 
Time-Based Units02/15/2022— — — — — — 17,341 449,999 
ROA Units02/15/2022— — — 2,168 8,671 17,342 — 225,012 
TUR Units02/15/2022— — — 2,168 8,671 17,342 — 331,926 
Catherine A. Green— — 320,000 — — — — — — 
Time-Based Units02/15/2022— — — — — — 12,524 324,998 
ROA Units02/15/2022— — — 1,566 6,262 12,524 — 162,499 
TUR Units02/15/2022— — — 1,566 6,262 12,524 — 239,709 
Craig W. Collins— — 586,500 — — — — — — 
Time-Based Units02/15/2022— — — — — — 32,755 849,992 
ROA Units02/15/2022— — — 4,095 16,378 32,756 — 425,009 
TUR Units02/15/2022— — — 4,095 16,378 32,756 — 626,950 
_________________________________________________________________________________________
(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 2022 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.
(3)Time-Based Units, ROA Units, and TUR Units were granted to Ms. Shults on May 2, 2022, in connection with her promotion to Senior Vice President and CFO.

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Outstanding Equity Awards at Year-End 2022

The following table reflects outstanding equity awards for each NEO as of December 31, 2022. The market values shown are based on WES’s closing unit price of $26.85 on December 30, 2022.

 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 Units222,686 5,979,119 — — 
ROA Units— — 357,536 9,599,842 
TUR Units— — 262,168 7,039,211 
Kristin S. Shults
Time-Based Units57,393 1,541,002 — — 
ROA Units— — 21,589 579,665 
TUR Units— — 13,548 363,764 
Christopher B. Dial
Time-Based Units46,627 1,251,935 — — 
ROA Units— — 79,855 2,144,107 
TUR Units— — 58,339 1,566,402 
Robert W. Bourne
Time-Based Units44,520 1,195,362 — — 
ROA Units— — 74,057 1,988,430 
TUR Units— — 54,775 1,470,709 
Catherine A. Green
Time-Based Units25,602 687,414 — — 
ROA Units— — 29,973 804,775 
TUR Units— — 21,552 578,671 
Craig W. Collins
Time-Based Units— — — — 
ROA Units— — 92,685 2,488,592 
TUR Units— — 71,490 1,919,507 
_________________________________________________________________________________________
(1)The table below shows the vesting dates for the respective time-based units listed in the above Outstanding Equity Awards at Year-End 2022 Table:
Vesting DateMr. UreMs. ShultsMr. DialMr. BourneMs. Green
02/12/2023122,901 23,246 26,145 25,612 13,054 
02/12/202470,883 18,636 14,701 13,127 8,373 
02/12/202528,902 15,511 5,781 5,781 4,175 
(2)The table below shows the performance periods for the respective ROA Units listed in the above Outstanding Equity Awards at Year-End 2022 Table. The number of outstanding ROA Units for each award is calculated based on WES’s return-on-assets performance as of December 31, 2022, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. As of December 31, 2022, WES’s performance under the ROA awards was 163.3%, 176.7%, and 199.2% for the performance periods ending December 31, 2022, 2023, and 2024, respectively.

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Performance PeriodMr. UreMs. ShultsMr. DialMr. BourneMs. GreenMr. Collins
1/1/2020 to 12/31/2022 (i)
76,452 — 15,290 17,839 6,372 31,589 
1/1/2021 to 12/31/2023194,725 — 47,292 38,945 11,127 51,750 
1/1/2022 to 12/31/202486,359 21,589 17,273 17,273 12,474 9,346 
_______________________________________________________________
(i)    Payment of these awards, earned for the performance period ending December 31, 2022, were made in February 2023 after the Compensation Committee’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.
(3)The table below shows the performance periods for the respective TUR Units listed in the above Outstanding Equity Awards at Year-End 2022 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, 2022, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. As of December 31, 2022, WES’s performance under the TUR awards was 150%, 125%, and 125% for the performance periods ending December 31, 2022, 2023, and 2024, respectively.
Performance PeriodMr. UreMs. ShultsMr. DialMr. BourneMs. GreenMr. Collins
1/1/2020 to 12/31/2022 (i)
70,226 — 14,045 16,386 5,853 29,016 
1/1/2021 to 12/31/2023137,751 — 33,455 27,550 7,871 36,609 
1/1/2022 to 12/31/202454,191 13,548 10,839 10,839 7,828 5,865 
________________________________________________________________
(i)    Payment of these awards, earned for the performance period ending December 31, 2022, were made in February 2023 after the Compensation Committee’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.

Option Exercises and Units Vested in 2022

The following table reflects information about the aggregate dollar value realized during 2022 by our NEOs for WES awards that vested in 2022.
 Unit Awards
Name
Number of Units 
Acquired on Vesting
(#) (1)
Value Realized
on Vesting
($) (2)
Michael P. Ure104,415 2,846,505 
Kristen S. Shults7,734 210,906 
Christopher B. Dial22,531 614,228 
Robert W. Bourne22,290 607,635 
Catherine A. Green9,776 266,514 
Craig W. Collins78,173 2,171,499 
_________________________________________________________________________________________
(1)The number of units acquired on vesting includes the time-based units that vested in 2022 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 2022

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 the Partnership’s 401(k) plan, a tax-qualified defined contribution plan.

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Nonqualified Deferred Compensation for 2022

The Partnership maintains the Western Midstream Savings Restoration Plan to provide a supplemental benefit to eligible employees, including the NEOs, 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 2022
Partnership Contributions in 2022 (1)
Aggregate Earnings / Losses in 2022
Aggregate Withdrawal / Distributions in 2022
Aggregate Balance at End of 2022 (2)
Michael P. Ure$— $284,701 $(15,693)$— $430,152 
Kristin S. Shults— 25,863 — — 25,863 
Christopher B. Dial— 83,141 (5,223)— 124,323 
Robert W. Bourne— 125,475 (7,776)— 201,344 
Catherine A. Green— 104,397 (3,550)— 132,382 
Craig W. Collins— 150,450 (9,648)— 228,665 
_________________________________________________________________________________________
(1)Reflects contributions earned for fiscal year 2022, although not credited to participant accounts until 2023. These contributions are reported in the Summary Compensation Table for each of the NEOs under the “All Other Compensation” column for the year 2022.
(2)The balance for each NEO includes Partnership contributions previously reported in the Summary Compensation Table for fiscal years prior to 2022 in the following aggregate amounts: Mr. Ure - $161,144; Ms. Shults - $0; Mr. Dial - $47,805; Mr. Bourne - $83,645; Ms. Green - $0; and Mr. Collins - $87,863.

Potential Payments Upon Termination or Change of Control

As of December 31, 2022, all of our NEOs were eligible for severance benefits under the ESP and CIC Plan that were amended and restated, and approved by our Board, in November 2022 (discussed in detail in the CD&A Severance section).
Upon Mr. Collins’s departure from the Partnership on November 11, 2022, he received the following benefits under the ESP: cash severance of $1,644,750 payable in lump sum; an annual bonus for 2022 in the amount of $794,668 paid at the same time as other executives; up to two years of continued health and welfare benefits at the employee rates, valued at $6,024; 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 $1,025,256. 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, 2022. The performance units will be paid after the end of the performance period based on actual performance. Mr. Collins will also be paid his previously earned and vested balance in the Savings Restoration Plan of approximately $235,000(1). Mr. Collins 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, 2022 and, where applicable, using the closing price of our common unit of $26.85 (as reported on the NYSE as of December 30, 2022). 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 2022 Table.



_________________________________________________________________________________________
(1)Due to Internal Revenue Code Section 409A, the final payment has yet to be made and the amount is subject to change.
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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. UreMs. ShultsMr. DialMr. BourneMs. Green
Cash Severance $— $— $— $— $— 
Total$— $— $— $— $— 

Involuntary Not For Cause Termination. As of December 31, 2022, the NEOs below were eligible for severance benefits under the ESP.
Mr. UreMs. ShultsMr. DialMr. BourneMs. Green
Cash Severance (1)
$3,487,500 $1,080,000 $1,147,500 $1,147,500 $1,080,000 
Pro-Rata Annual Cash Bonus (2)
1,520,938 502,400 533,800 533,800 502,400 
Pro-Rata Vesting of WES Equity Awards (3)
14,041,570 857,239 3,100,073 2,963,890 1,157,612 
Continuation of Welfare Benefits (4)
60,085 41,680 15,639 44,940 41,680 
Total$19,110,093 $2,481,319 $4,797,012 $4,690,130 $2,781,692 
_________________________________________________________________________________________
(1)Reflects amounts payable in lump 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 Ms. Shults; Messrs. Dial and Bourne, and Ms. Green reflect 1.5 times the sum of their current base salary plus target bonus.
(2)The amounts reflect a prorated annual bonus, assuming each NEO’s employment terminated on December 31, 2022.
(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, 2022. 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. Amounts include the value of the 2020 annual performance unit awards with performance periods that ended December 31, 2022, but were not settled until February 2023.
(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.

Good Reason Termination Under the ESP. As of December 31, 2022, 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. UreMs. ShultsMr. DialMr. BourneMs. Green
Cash Severance (1)
$3,487,500 $1,080,000 $1,147,500 $1,147,500 $1,080,000 
Pro-Rata Annual Cash Bonus (2)
1,520,938 502,400 533,800 533,800 502,400 
Pro-Rata Vesting of WES Equity Awards (3)
14,041,570 857,239 3,100,073 2,963,890 1,157,612 
Continuation of Welfare Benefits (4)
60,085 41,680 15,639 44,940 41,680 
Total$19,110,093 $2,481,319 $4,797,012 $4,690,130 $2,781,692 
_________________________________________________________________________________________
(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 Ms. Shults; Messrs. Dial and Bourne, and Ms. Green 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, 2022.
(3)Awards granted prior to 2022 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 50% or more of the voting power in the Partnership or General Partner; (ii) the approval of the Partnership’s 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. UreMs. ShultsMr. DialMr. BourneMs. Green
Cash Severance (1)
$5,213,813 $1,440,000 $1,530,000 $1,530,000 $1,440,000 
Pro-Rata Annual Cash Bonus (2)
1,520,938 502,400 533,800 533,800 502,400 
Pro-Rata Vesting of WES Equity Awards (3)
14,041,570 857,239 3,100,073 2,963,890 1,157,612 
Continuation of Welfare Benefits (4)
60,085 41,680 15,639 44,940 41,680 
Total$20,836,406 $2,841,319 $5,179,512 $5,072,630 $3,141,692 
_________________________________________________________________________________________
(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 Ms. Shults, Messrs. Dial and Bourne, and Ms. Green 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 2022, 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, 2022. In the event of a change of control, the performance would be calculated based on the change of control date. Amounts include the value of 2020 annual performance unit awards with performance periods that ended December 31, 2022, but were not settled until February 2023.
(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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Death or Termination due to Disability
Mr. UreMs. ShultsMr. DialMr. BourneMs. Green
Cash Severance (1)
$22,618,172 $2,484,431 $4,962,444 $4,654,501 $2,070,860 
Total$22,618,172 $2,484,431 $4,962,444 $4,654,501 $2,070,860 
______________________________________________________________________________________
(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, 2022. 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. Amounts include the value of 2020 annual performance unit awards with performance periods that ended December 31, 2022, but were not settled until February 2023.

CEO Pay Ratio

In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of our employees and the annual total compensation of Michael P. Ure, our President and Chief Executive Officer.
For the 2022 calendar year, the annual total compensation of Mr. Ure, as reported in the Summary Compensation Table for this Item 11, was $7,648,005. The median of the annual total compensation of all employees of the Partnership (other than our CEO) was $166,363. Based on this information, for 2022, Mr. Ure’s total annual compensation was 46 times that of the median of the annual total compensation of all employees.
As permitted by the SEC rules, the median employee utilized for the pay ratio disclosure for the fiscal year ended 2022 is the same employee identified for our prior pay ratio disclosure for the fiscal year ended 2020 because there were no changes during our fiscal year ended 2021 or 2022 with respect to our employee population, employee compensation arrangements, or to the same median employee’s circumstances that we reasonably believe would result in a significant change to this pay ratio disclosure. In preparing this pay ratio disclosure, we took the following steps:

•We determined that, as of December 31, 2022, our employee population consisted of 1,217 individuals with all of these individuals located in the United States (as reported in the Human Capital Resources section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K). This population consisted of all employees, whether employed on a full-time or part-time basis.

•In originally identifying the “median employee” for purposes of our prior pay ratio disclosure for the fiscal year ended 2020, we compared the 2020 earnings eligible under the short-term incentive plan plus the short-term incentive earned in 2019 that was paid in 2020 as reflected in our payroll records for 2020. We identified our median employee using this compensation measure, which was consistently applied to all our employees included in the calculation. We did not make any estimates, assumptions, or adjustments to the data in identifying the “median employee.”

•With respect to calculating the total annual compensation disclosed above for the median employee, we combined all of the elements of such employee’s total compensation for 2021.

•The pay ratio disclosed above is a reasonable estimate calculated in accordance with SEC rules, based on our records and the methodologies described above. The SEC rules for identifying the median compensated employee and calculating the pay ratio allow companies to use a variety of methodologies and apply various assumptions. The application of various methodologies may result in significant differences in the results reported by other SEC reporting companies. As a result, the pay ratio reported by other SEC reporting companies may differ substantially from, and may not be comparable to, the pay ratio we disclose above.
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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 2022, 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 2022 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 for the 2022 calendar year. The only change made to the program in 2022 was the increase of the annual phantom unit grant from $125,000 to $145,000.

Compensation for non-employee directors during 2022 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 $145,000.

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.

The following table sets forth information concerning total director compensation earned during 2022 by each non-employee director:
NameFees Earned or Paid in Cash
($)
Stock
Awards 
($) (1)
Total
($)
Oscar K. Brown133,750 145,009 278,759 
Kenneth F Owen134,000 145,009 279,009 
David J. Schulte134,000 145,009 279,009 
Lisa A. Stewart133,250 145,009 278,259 
________________________________________________________________________________________
(1)The amounts included in the Stock Awards column represent the grant date fair value of phantom units made to directors in 2022, 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 2022. As of December 31, 2022, Messrs. Brown, Owen, and Schulte and Ms. Stewart each had 5,588 outstanding phantom units.


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The table below contains the grant date fair value of phantom unit awards made to each non-employee director during 2022:
NameGrant Date
Phantom 
Units 
(#) (1)
Grant Date Fair 
Value of Stock Awards
($) (2)
Oscar K. BrownFebruary 155,588 145,009 
Kenneth F OwenFebruary 155,588 145,009 
David J. SchulteFebruary 155,588 145,009 
Lisa A. StewartFebruary 155,588 145,009 
_________________________________________________________________________________________
(1)The phantom units granted on February 15, 2022, will vest in full on February 12, 2023, 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 2022 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

While WES does have a Compensation Committee, our Board continues to make substantive compensation decisions for WES’s executive officers at the recommendation of the 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 16, 2023:

•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)
190,281,578 49.4%
Peter J. Bennett— *
Michael P. Ure292,051 *
Kristen S. Shults23,229 *
Robert W. Bourne71,637 *
Christopher B. Dial64,745 *
Catherine A. Green28,425 *
Oscar K. Brown (3)
22,703 *
Nicole E. Clark — *
Frederick A. Forthuber — *
Kenneth F. Owen 20,642 *
David J. Schulte 25,142 *
Lisa A. Stewart 20,642 *
All directors and executive officers
as a group (12 persons)		569,216 *
_________________________________________________________________________________________
*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 14,139,260 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
25,442,166 (1)
6.62%
_________________________________________________________________________________________
(1)Based upon its Schedule 13G/A filed February 13, 2023, with the SEC with respect to Partnership securities held as of December 31, 2022, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 25,442,166 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 25,280,927 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, 2022. 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
1,441,656 (1)
— (2)
11,428,415 
Equity compensation plans not approved by security holders
1,802,642 (1)
— (2)
— 
Total3,244,298 — 11,428,415 
_________________________________________________________________________________________
(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 16, 2023, Occidental held (i) 190,281,578 of our common units, representing a 48.3% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.3% 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. Other than our CEO, who serves as a director, three of our directors are currently affiliated with Occidental and our remaining four 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,
thousands202220212020
Revenues and other
Service revenues – fee based$1,674,959 $1,589,367 $1,740,999 
Service revenues – product based56,907 11,888 8,509 
Product sales63,367 31,103 71,104 
Total revenues and other1,795,233 1,632,358 1,820,612 
Equity income, net – related parties (1)
183,483 204,645 226,750 
Operating expenses
Cost of product (2)
(25,447)42,805 92,884 
Operation and maintenance5,081 27,805 49,533 
General and administrative (3)
2,338 15,613 40,295 
Total operating expenses(18,028)86,223 182,712 
Gain (loss) on divestiture and other, net(1,756)420 (2,870)
Interest income – Anadarko note receivable— — 11,736 
_________________________________________________________________________________________
(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 related-party natural-gas and NGLs imbalances.
(3)Includes 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). Balances for the years ended December 31, 2021 and 2020, also include amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Item 13).

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Consolidated balance sheets
December 31,
thousands20222021
Assets
Accounts receivable, net$313,937 $180,205 
Other current assets1,578 12,490 
Equity investments (1)
944,696 1,167,187 
Other assets29,058 45,494 
Total assets1,289,269 1,405,376 
Liabilities
Accounts and imbalance payables32,150 49,242 
Accrued liabilities11,756 13,914 
Other liabilities268,399 207,365 
Total liabilities312,305 270,521 
_________________________________________________________________________________________
(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,
thousands202220212020
Distributions from equity-investment earnings – related parties$186,153 $213,516 $246,637 
Capital expenditures(470)(2,000)— 
Contributions to equity investments - related parties(9,632)(4,435)(19,388)
Distributions from equity investments in excess of cumulative earnings – related parties63,897 41,385 32,160 
Distributions to Partnership unitholders (1)
(372,468)(272,192)(381,949)
Distributions to WES Operating unitholders (2)
(24,898)(14,984)(15,434)
Net contributions from (distributions to) related parties1,423 8,533 24,466 
Proceeds from the sale of assets to related parties200 — — 
Finance lease payments (3)
— — (6,382)
Unit repurchases from Occidental (4)
(252,500)(50,225)— 
_________________________________________________________________________________________
(1)Represents common and general partner unit 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)Included in Other cash flows from financing activities in the consolidated statements of cash flows under Part II, Item 8 of this Form 10-K.
(4)Represents common 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).


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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,
thousands202220212020
General and administrative (1)
$5,373 $18,365 $41,609 
_________________________________________________________________________________________
(1)Includes (i) an intercompany service fee between WES and WES Operating and (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). Balances for the years ended December 31, 2021 and 2020, also include amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Item 13).

Consolidated balance sheets
December 31,
thousands20222021
Accounts receivable, net$313,937 $180,205 
Other current assets1,487 12,490 
Other assets28,459 45,494 
Accounts and imbalance payables (1)
76,131 97,749 
Accrued liabilities11,439 13,597 
_________________________________________________________________________________________
(1)Includes balances related to transactions between WES and WES Operating.

Consolidated statements of cash flows
Year Ended December 31,
thousands202220212020
Distributions to WES Operating unitholders (1)
$(1,244,533)$(749,018)$(771,546)
_________________________________________________________________________________________
(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 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, 2022, production owned or controlled by Occidental represented 35% 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 80% of our throughput for produced-water assets.
We are currently discussing varying interpretations of certain contractual provisions with Occidental regarding the calculation of the cost-of-service rates under an oil-gathering contract related to our DJ Basin oil-gathering system. If such discussions are 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.

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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 (“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 ended as of September 30, 2022.

Marketing Transition Services Agreement. During the year ended December 31, 2020, Occidental provided marketing-related services to certain of our subsidiaries (the “Marketing Transition Services Agreement”). While we still have some marketing agreements with affiliates of Occidental, on January 1, 2021, we began marketing and selling substantially all our crude oil and residue gas, and a majority of our NGLs, directly to third parties.

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 is being amortized to Operation and maintenance expense over the remaining term of the agreements.

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 the Partnership and WES Operating (“Services Agreement”). 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 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 $2.3 million, $10.1 million, and $14.6 million for the years ended December 31, 2022, 2021, and 2020, respectively. As of December 31, 2022, there is no unrecognized compensation expense attributable to Incentive Plans. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Construction reimbursement agreements and purchases and sales with 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 and sell equipment, inventory, and other miscellaneous assets from or to Occidental or its affiliates.

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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, 2022, 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
thousands2022202120222021
Audit fees$250 $400 $2,673 $2,100 
Total$250 $400 $2,673 $2,100 

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 Chairperson, to whom such authority has been conditionally delegated, prior to engagement. During 2022, 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 2022, 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, 2023.

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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
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
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Exhibit
Number		Description
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
10.1
10.2
10.3
10.4
10.5
‡10.6
10.7
10.8
10.9
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Exhibit
Number		Description
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
10.25
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Exhibit
Number		Description
10.26
10.27
10.28
10.29
10.30
10.31
†10.32
†10.33
†10.34
†10.35
†10.36
†10.37
10.38
*21.1
*23.1
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Exhibit
Number		Description
24.1
*31.1
*31.2
*31.3
*31.4
**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 22, 2023
/s/ Michael P. Ure
Michael P. Ure
President and Chief Executive Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
February 22, 2023
/s/ Kristen S. Shults
Kristen S. Shults
Senior Vice President and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
February 22, 2023
/s/ Michael P. Ure
Michael P. Ure
President and Chief Executive Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
February 22, 2023
/s/ Kristen S. Shults
Kristen S. Shults
Senior Vice President 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 and Kristen S. Shults, and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, 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 attorneys-in-fact and agents, and each of them, 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 attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, 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 22, 2023.

SignatureTitle (Position with Western Midstream Holdings, LLC)
/s/ Peter J. BennettChairperson
Peter J. Bennett
/s/ Michael P. UrePresident, Chief Executive Officer and Director
Michael P. Ure(Principal Executive and Financial Officer)
/s/ Kristen S. ShultsSenior Vice President and Chief Financial Officer
Kristen S. Shults(Principal 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

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