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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, 2023

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, 2023, based on the closing price as reported on the New York Stock Exchange.
Western Midstream Partners, LP$5.1 billion
Western Midstream Operating, LPNone
Common units outstanding as of February 14, 2024:
Western Midstream Partners, LP380,483,668
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
ItemPage
1 and 2.
1A.
1B.
1C.
3.
4.
5.
7.
7A.
8.
9.
9A.
9B.
9C.
4

5

COMMONLY USED ABBREVIATIONS AND TERMS
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. The following list of abbreviations and terms are used in this document:
Defined TermDefinition
AnadarkoAnadarko 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.
Barrel, Bbl, Bbls/d, MBbls/d42 U.S. gallons measured at 60 degrees Fahrenheit, barrels per day, thousand barrels per day.
BoardThe 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, in which we are the managing member of and own a 75% interest.
Chipeta LLC agreement
Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009.
CondensateA natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions.
DBM water systems
Produced-water gathering and disposal systems in West Texas.
Delivery pointThe 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, Fort Lupton, Wattenberg, Lancaster, and Latham processing plants, and the Wattenberg gathering system.
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.
Equity-investment throughput
Our share of average throughput from investments accounted for under the equity method of accounting.
Exchange ActThe Securities Exchange Act of 1934, as amended.
Floating-Rate Senior Notes due 2023WES Operating’s floating-rate Senior Notes due 2023, which were fully repaid in January 2023.
FERC
The Federal Energy Regulatory Commission.
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.
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.
Marcellus Interest
The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania.
Mcf, MMcf, MMcf/d
Thousand cubic feet, million cubic feet, million cubic feet per day.
Meritage
Meritage Midstream Services II, LLC, which was acquired by the Partnership on October 13, 2023.
MIGCMIGC, LLC.
Mi Vida
Mi Vida JV LLC, in which we own a 50% interest.
MLP
Master limited partnership.
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.
NYSENew York Stock 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.
6

Defined TermDefinition
OTTCOOverland Trail Transmission, LLC.
Panola
Panola Pipeline Company, LLC, in which we own a 15% interest.
Powder River Basin complex
The Hilight system and assets acquired from Meritage, which includes a gathering system, processing plants, and the Thunder Creek NGL pipeline (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
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).
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 Red Desert gathering lines and related facilities.
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.
Saddlehorn
Saddlehorn Pipeline Company LLC, in which we own a 20% interest.
SEC
U.S. Securities and Exchange Commission.
Services Agreement
That certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP.
Springfield system
The Springfield gas-gathering system and Springfield oil-gathering system.
Stabilization
The process to reduce the volatility of a liquid hydrocarbon stream by separating very light hydrocarbon gases, methane and ethane in particular, from heavier hydrocarbon components. This process reduces the volatility of the liquids during transportation and storage.
TailgateThe point at which processed natural gas and/or natural-gas liquids leave a processing facility for end-use markets.
TEG
Texas Express Gathering LLC, in which we own a 20% interest.
TEP
Texas Express Pipeline LLC, in which we own a 20% interest.
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 Delaware Basin Midstream complex and DBJV and Haley systems.
WGRAH
WGR Asset Holding Company LLC, 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
The $1.25 billion buyback program ending December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.
$250.0 million Purchase Program
The $250.0 million buyback program ending December 31, 2021. As of December 31, 2021, the entire $250.0 million authorized program had been fulfilled.

7
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, 2023 (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 our customers under certain contracts.
Our gathering systems transport raw, or untreated, natural gas from our customers’ wellheads or production facilities to a central location for treating and processing. During processing, unwanted contaminants are removed and natural gas is separated into pipeline quality natural gas, or residue gas, and a mixed NGLs stream that are then transported and marketed to end-use markets or for additional processing. Our crude-oil assets gather raw, high and low vapor-pressure oil at the well site to be processed at oil stabilization facilities before being delivered to crude-oil terminals, storage facilities, long-haul crude-oil pipelines, and refineries. In addition, our produced-water gathering and disposal systems provide the link between well sites or nearby collection points and disposal facilities that (i) 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 or (ii) sell the produced water to third parties to be treated and recycled.

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

wesusmap2023.jpg
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As of December 31, 2023, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
18 2 3 1 
Treating facilities38 3 — — 
Natural-gas processing plants/trains24 3 — 3 
NGLs pipelines3 — — 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, 2023:
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 Disposal4,280896,95133 %2,0402,4482,050 289 1,029 
Transportation1,978— — — — 324 220 — 
Rocky MountainsGathering, Processing, and Treating7,147673,362 50 %3,160 221 1,986 71 — 
Transportation2,243— — — — 113 85 — 
North-central PennsylvaniaGathering14615,180 — %— — 120 — — 
Total15,7941,585,493 39 %5,200 2,669 4,593 665 1,029 
_________________________________________________________________________________________
(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, 2023, 2022, and 2021, and total assets for the years ended December 31, 2023 and 2022.

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ACQUISITIONS AND DIVESTITURES

Meritage. In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF.

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 and Note 13—Debt and Interest Expense under Part II, Item 8 of this Form 10-K.

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, DJ, and Powder River 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 95% 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, 2023. 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, 2023, we had approximately 2.6 Bcf/d for our natural-gas assets (excluding equity investments), approximately 465 MBbls/d for our crude-oil and NGLs assets (excluding equity investments), and approximately 860 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, 2023, there was $1.4 billion in effective borrowing capacity under the RCF after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for our commercial paper program.

•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 to service 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, 2023, Occidental held (i) 185,181,578 of our common units, representing a 47.7% 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, 2023, Occidental held 48.8% of our outstanding common units.
For the year ended December 31, 2023, 59% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% 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 Anadarko Energy Services Company (“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 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.

13
PROPERTIES

The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, 2023.

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 1,640 53 624,074 3 1,914 
West Texas
DBM oil system (5)
Gathering & Treating16 — 310 12,648 1 654 
West TexasDBM water systemsGathering & Disposal— — 1,825 92,395 5 799 
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 — 75 118,434 2 855 
Total402,0402,448896,951124,280
_________________________________________________________________________________________
(1)Includes 215 MMcf/d of bypass capacity at the West Texas complex.
(2)Includes owned and leased compressors and compression horsepower.
(3)Includes 19 miles of transportation related to the 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 Regional oil treating facilities.
(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

wtx2023.jpg

West Texas gathering, processing, and treating complex

•Customers. For the year ended December 31, 2023, Occidental’s production represented 42% of the West Texas complex throughput, and the two largest third-party customers provided 32% 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 within the West Texas complex. Mentone Train III will have a capacity of 300 MMcf/d, and WES expects this train to be completed at the end of the first quarter of 2024. Upon completion of Mentone Train III, the West Texas complex will have a total processing capacity of 1,940 MMcf/d.

•North Loving Plant. WES is currently constructing a new cryogenic processing plant in the North Loving area of our West Texas complex. The North Loving Plant will have a capacity of 250 MMcf/d, and WES expects this plant to be completed in the first quarter of 2025.

DBM oil-gathering system, treating facilities, and storage

•Customers. As of December 31, 2023, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2023, 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, 2023, DBM water systems throughput was from Occidental and numerous third-party producers, with Occidental’s production representing 78% 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, 2023, 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
etx2023.jpg

Mont Belvieu JV fractionation trains

•Customers. The Mont Belvieu JV does not contract with customers directly but is allocated volumes based on available capacity and the allocation structure set forth in the Operating Agreement between Mont Belvieu JV and Enterprise Products Operating, LLC.

•Supply and delivery points. Enterprise Products Partners L.P. (“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
stx2023.jpg

Brasada gathering, stabilization, treating, and processing complex

•Customers. For the year ended December 31, 2023, 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, 2023, 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 59 354,444 2 1,798 
ColoradoDJ Basin oil systemGathering & Treating6 — 155 6,095 1 448 
Utah
Chipeta (4)
Processing3 790 — 76,125 — 2 
Total252,540214436,66432,248
_________________________________________________________________________________________
(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
co2023.jpg
19
DJ Basin gathering, treating, and processing complex

•Customers. For the year ended December 31, 2023, Occidental’s production represented 51% of the DJ Basin complex throughput, and the two largest third-party customers provided 34% of the throughput.

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

•Delivery points. As of December 31, 2023, 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, 2023, 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 centralized oil stabilization facility (“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
ut2023.jpg

Chipeta processing complex

•Customers. For the year ended December 31, 2023, Chipeta complex throughput was from numerous third-party customers, with the two largest customers providing 71% 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.

•Expansion activity. Additional compression is in the process of being installed at the Chipeta complex, which will allow for up to 100 MMcf/d of incremental inlet gas via MountainWest Pipeline and is expected to be in service in July 2024.
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Overview - Rocky Mountains - Wyoming
LocationAssetTypeProcessing / Treating PlantsProcessing / Treating Capacity (MMcf/d)Processing / Treating Capacity (MBbls/d)Compression HorsepowerGathering Systems
Pipeline Miles (1)
Northeast Wyoming
Powder River Basin complex (2)
Gathering, Processing, & Treating6 620 7 185,816 2 2,715 
Southwest WyomingGranger complexGathering— — — 21,673 1 779 
Southwest WyomingRed Desert complexGathering— — — 20,809 1 1,119 
Southwest Wyoming
Rendezvous (3)
Gathering— — — 8,400 1 286 
Total66207236,69854,899
_________________________________________________________________________________________
(1)Includes 120 miles of transportation related to a FERC-regulated NGL pipeline at the Powder River Basin complex.
(2)The Powder River Basin complex includes the Hilight system and assets acquired from Meritage (Steamboat and 50 Buttes gas-processing plants, Buckshot amine plant, Thunder Creek gathering system, and Thunder Creek NGL pipeline).
(3)We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.

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Northeast Wyoming

Powder River Basin gathering, processing, and treating complex

The Powder River Basin complex includes the Hilight system and assets acquired with the closing of the Meritage acquisition in October 2023. See Acquisitions and Divestitures within these Items 1 and 2.

•Customers. For the year ended December 31, 2023, gas gathered and processed at the Powder River Basin complex was from numerous third-party customers, with the largest customer providing 36% of the system throughput.

•Supply. The Powder River Basin complex serves the gas-gathering needs of several conventional producing fields in Converse, Campbell, Johnson, and Natrona 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. The Steamboat and 50 Buttes gas-processing plants deliver natural gas to the Thunder Creek and Chalk Buttes delivery points owned by Wyoming Interstate Company (“WIC”), a subsidiary of Kinder Morgan, Inc. The NGLs from the Steamboat and 50 Buttes gas-processing plants, as well as EOG’s Jewell gas-processing plant, are delivered via our Thunder Creek NGL pipeline to ONEOK, Inc.’s Well Draw delivery point.

Southwest Wyoming

Granger gathering system

The Granger processing plant was shut down in December 2023. The gathering system continues to be operational, and gas gathered by the system is delivered to a third party for processing.

•Customers. For the year ended December 31, 2023, Granger complex throughput was from third-party customers, with the two largest customers providing 77% 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 is delivered to a third party for processing and can then be delivered to the CIG pipeline; The Williams Companies, Inc.’s MountainWest Pipeline, Overthrust Pipeline, and 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 gathering system

•Customers. For the year ended December 31, 2023, Red Desert complex throughput was from third-party customers, with the three largest customers providing 59% 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, 2023, 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 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 3 146 
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(1)We own a 33.75% interest in the Marcellus Interest gathering systems.
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Marcellus gathering systems

•Customers. As of December 31, 2023, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided approximately 89% of the throughput for the year ended December 31, 2023. 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

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LocationAssetTypeOwnership InterestPipeline Miles
Colorado, Kansas, Oklahoma
White Cliffs (1) (2)
Oil & NGLs10.00 %1,066 
Wyoming, Colorado, Kansas, Oklahoma
Saddlehorn (1) (2)
Oil20.00 %604 
Utah
GNB NGL (1)
NGLs100.00 %33 
Northeast Wyoming
MIGC (1)
Gas100.00 %244 
Southwest WyomingOTTCOGas100.00 %234 
Southwest WyomingWamsutterOil100.00 %62 
Colorado, Oklahoma, Texas
FRP (1) (2)
NGLs33.33 %452 
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 %253 
Texas
Red Bluff Express (1) (2)
Gas30.00 %123 
Total4,221 
_________________________________________________________________________________________
(1)Regulated by FERC.
(2)Operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline. The White Cliffs dual pipeline system had multiple committed shippers, including Occidental, as of December 31, 2023. Other parties may also ship on the White Cliffs pipeline at FERC-based rates. The pipeline provides crude-oil and NGL takeaway capacity from Platteville, Colorado, to ET’s storage facility in Cushing, Oklahoma, which ultimately delivers to Gulf Coast and mid-continent refineries. It is supplied by production from the DJ Basin. At the point of origin, there is a storage facility adjacent to a truck-unloading facility.

Saddlehorn pipeline. The Saddlehorn pipeline had multiple committed shippers, including Occidental, as of December 31, 2023. Other parties may also ship on the Saddlehorn pipeline at FERC-based rates. The pipeline has multiple origin points including: Cheyenne and Ft. Laramie, Wyoming, and Carr and Platteville, Colorado. Saddlehorn is supplied by the DJ Basin and basins that connect to a Wyoming access point. The pipeline delivers crude oil and condensate to storage facilities in Cushing, Oklahoma.

Rocky Mountains - Utah

GNB NGL pipeline. There were three primary shippers on the GNB NGL pipeline as of December 31, 2023. The GNB NGL pipeline provides capacity at the posted FERC-based rates and has the ability to receive NGLs from Chipeta’s gas-processing facility and MPLX’s Stagecoach/Iron Horse gas-processing complex. 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. For the year ended December 31, 2023, throughput on the MIGC system was from numerous third-party customers, with the two largest customers providing 80% of the system throughput. All parties on the MIGC system ship pursuant to a tariff on file with FERC. The system receives gas from the Hilight system, EOG’s Jewell plant, and from WBI Energy Transmission, Inc. 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.


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OTTCO transportation system. For the year ended December 31, 2023, throughput on the OTTCO transportation system was from numerous third-party shippers. Revenues on the system are generated from contracts that contain minimum-volume commitments and volumetric fees paid by shippers under firm and interruptible gas-transportation agreements. Supply points 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. For the year ended December 31, 2023, 96% of the Wamsutter pipeline throughput was from one third-party shipper. Revenues on the pipeline are generated from tariff-based rates regulated by the Wyoming Public Service Commission. The Wamsutter pipeline has active receipt points in Sweetwater County, Wyoming, and delivers crude oil to MPLX LP’s SLC Core Pipeline System.

Texas

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, 2023, the pipeline 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, 2023.

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, 2023, the pipeline had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates.

Whitethorn. 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. The Panola pipeline transports NGLs from Panola County, Texas, to Mont Belvieu, Texas. As of December 31, 2023, the Panola pipeline had multiple committed shippers. The pipeline provides capacity to other shippers at the posted FERC-based rates.

Red Bluff Express pipeline. As of December 31, 2023, the Red Bluff Express pipeline had multiple committed shippers, including Occidental. The 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. The 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, operational 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.

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 (“DOT”). Natural-gas pipelines are subject to PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”). Crude-oil and NGLs pipelines are subject to PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”). 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 allowable operating pressures (“MAOP”), 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.
The following are examples of proposed and/or final pipeline safety and maintenance regulations or other regulatory initiatives that could have a potentially material impact on our business:

•The Mega Rule. PHMSA has issued what it calls the “Mega Rule,” which is grouped into three tranches of rules published over several years, with roll out and implementation spanning more than a decade. In October 2019, PHMSA published Mega Rule Part One, which, among other things, requires operators of certain gas transmission pipelines to determine the material strength of their lines by reconfirming the MAOP and to identify moderate consequence areas (“MCAs”), which are extended covered segments of pipeline. 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 published Mega Rule Part Two focused on improving pipeline integrity management best practices. This rule implements changes to integrity, operating, and compliance procedures, and includes new requirements for natural-gas pipelines, including regulated onshore gathering lines and pipeline segments. The rule also includes increased regulatory requirements for operations and maintenance, integrity management, and data integration. In August 2022, PHMSA published Mega Rule Part Three, which became effective in May 2023. This rule increases corrosion control requirements, requires inspections following extreme weather events, extends the management of change process to areas that are not HCAs, and strengthens repair criteria. Compliance with the Mega Rule will increase operational costs for our business as we seek to develop and implement appropriate compliance procedures.
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•Leak Detection and Repair. In May 2023, PHMSA proposed revisions to the pipeline safety regulations to enhance leak detection and repair requirements for gas distribution, gas transmission, gas gathering, underground natural-gas storage, and liquefied natural-gas storage facilities. The proposed rule requires use of commercially available, advanced technologies to find and fix leaks of methane and gases. If finalized, the rule would, among other things, increase frequency of leakage survey and patrolling requirements, require advanced leak detection technology, lower the minimum reporting threshold for leaks, and establish specific criteria and timeframes for fixing equipment. If implemented, the rule could increase manpower and equipment expenditures for implementation and ongoing compliance.

•Gas Gathering Safety. In August 2023, PHMSA proposed a rule to strengthen safety requirements for gas distribution pipelines, incorporating revisions mandated by Congress to the Leonel Rondon Pipeline Safety Act, enacted as part of the Protecting our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020, as well as to address National Transportation Safety Board (“NTSB”) recommendations. The proposal includes requirements regarding construction procedures to minimize the risk of over-pressurization incidents, Distribution Integrity Management Program revisions to prepare for over-pressurization incidents, design of regulator stations with secondary pressure relief valves and remote gas monitoring, enhanced emergency response plans, and other requirements. As with other regulatory requirements, if implemented, these rules can increase implementation and ongoing compliance costs.

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.

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;
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•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 and Thunder Creek NGL pipelines provide 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 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.
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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 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 those owned by 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.
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. Red Bluff Express is required to meet certain quarterly reporting requirements, providing detailed transaction information that could be made public. This pipeline also is subject to periodic rate review by FERC. In addition, FERC’s anti-manipulation, market-oversight, and market-transparency regulations may
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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.

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 for new, reconstructed, modified, and existing sources, 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;
•regulations imposed by the U.S. Army Corps of Engineers (“Corps”) that govern and restrict activities that may affect federally regulated waters and wetlands;
•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 (“ESA”), 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, and similar protections for migratory birds under the Migratory Bird Treaty Act (“MBTA”);
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•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.

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,
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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:

•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. Subsequently, in January 2021, the Biden Administration announced that it will reconsider the December 2020 final action in favor of a more stringent ground-level ozone standard. Ongoing state implementation of the 2015 NAAQS, as well as potential implementation of even more stringent ground-level ozone standards, could, among other things, require installation of new emission controls on some of our or our customer’s equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

•Reduction of Methane and Other 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, 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 December 2023, the EPA finalized the new NSPS and Emissions Guidelines (“EGs”), known as Subpart OOOOb and Subpart OOOOc, respectively, to further reduce methane and VOC emissions from new, modified, reconstructed, and existing sources in the oil and natural-gas sector, including previously unregulated sources. The rules set more stringent standards and requirements for a variety of sources including flares, wells, storage vessels, compressors, pumps, sweeting units, performance leak detection, and others. Among the many additional requirements, one notable addition is the creation of a Super Emitter Program that, among other things, authorizes third parties to remotely monitor regulated facilities and notify the EPA when certain emissions events are detected. Subpart OOOOb generally becomes effective within 60 days after the rule is published, with certain exceptions. Subpart OOOOc, which will apply to existing sources, has a longer implementation timeline, requiring each state to submit a plan to the EPA for appropriate emissions reductions within two years of the date that the rule is published, and regulated entities are required to comply with state or federal rules within three years after the deadline for state plan submittals. Although any state rules implementing the methane rules must be more stringent than the federal rules, we cannot predict the full scope of any final methane regulatory requirements imposed by the states or the cost to comply with such requirements. Also, 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 GHG emissions. 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 GHG emissions under existing Clean Air Act provisions and may require the installation of “best available control technology” to limit GHG emissions from any new or significantly modified facilities that we may seek to construct in the
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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, processing, and gathering and boosting 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. To seek to meet that goal, in 2022, Congress enacted the Inflation Reduction Act, which, among other things, added Section 136 to the Clean Air Act and imposed the first-ever direct federal “charge” on methane emissions called the “Waste Emissions Charge” for applicable facilities within nine segments of the oil and natural gas industry. The IRA states that it will apply to methane emissions beginning in 2024, with the first charge for 2024 emissions due in 2025. On January 26, 2024, the EPA proposed rulemaking to establish a regulatory program for assessing and remitting a fee on methane emissions. Additionally, 2021 state legislation in Colorado requires the development of air quality regulations that will result in a 20% reduction in combustion greenhouse gas emissions from the midstream sector by 2030 as compared to a 2015 baseline. Rulemaking that is responsive to this legislation is expected in December 2024, and could require the replacement of gas-fired compressor engines with electric-driven compressor motors at a significant cost to us. In 2024, Colorado is rulemaking for a GHG emissions fee and likely SIP rulemaking to address severe nonattainment. Additionally, in December 2021, the AQCC adopted regulations that increase leak detection and repair inspections at certain oil and natural gas facilities, require the reduction of methane emissions from certain oil and natural gas operations, and impose certain GHG intensity standards. Generally, GHG intensity standards set numerical limits of carbon dioxide equivalent (CO2e) emissions per barrel of oil produced. In July 2023, the AQCC adopted a new rule to define how certain oil and gas facilities must calculate their greenhouse gas intensity, monitor operations to ensure compliance with intensity standards, new standards for engines, and keep records to accurately account for emissions from their 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.

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.

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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.

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, 2023, WES employed 1,377 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 2023 voluntary attrition rate was 9.73%, 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 and the amount of such distributions;

•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, keep-whole, and fixed-recovery processing 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 and commercial paper program;

•our ability to repay debt;

•the resolution of litigation or other disputes;

•conflicts of interest among us and 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, 2023, 59% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% 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, leverage, 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, in part, 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
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Occidental and us. For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us.
Any future credit-rating downgrade could negatively impact our cost of and ability to access capital.
Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit rating assigned to WES Operating’s debt by the major credit rating agencies. Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt, including commercial paper, 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 $2.8 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, 2023, 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 declined during 2023, the prices of key inputs to the midstream industry have continued to be significantly impacted by inflation relative to historical levels. This continued inflation has raised our costs for steel products, automation components, power supply, labor materials, fuel, chemicals, 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, sustained or further increases in inflation would negatively impact our profitability and cash flows available for distribution to unitholders to the extent we are unable to recover such higher costs through our commercial agreements.
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 2023 distribution of $0.57500 per unit per quarter, or $2.30000 per unit per year, we require per-quarter available cash of $223.4 million, or $893.6 million per year, based on the number of common units outstanding at February 1, 2024. 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.
Across our asset portfolio, we rely on third-party customers for a substantial amount of our revenues. 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.
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.
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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, now renamed as the Energy & Carbon Management Commission (“ECMC”), 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, the ECMC 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. Since July 2019, the ECMC has conducted rulemaking hearings to adopt rules required in the bill, and adopted rules in 2019, 2020 and 2021 to implement the provisions of Senate Bill 19-181. Rules adopted include those related to wellbore integrity, financial assurance, worker certification, and the like. 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.
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,
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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”), 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, Notes, and the commercial paper program.
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.
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-
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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. 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.
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
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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.
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
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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 we 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 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 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
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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 may fail to successfully combine our business with the assets and business of Meritage, which could have an adverse impact on our future results.

The Meritage acquisition closed on October 13, 2023. The integration of these acquired assets involve potential risks, including the failure to realize expected profitability, growth, or accretion; environmental or regulatory compliance matters or liabilities; diversion of management’s attention from our existing business; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.
If any of the risks described above or other anticipated or unanticipated liabilities were to materialize, it could have an adverse effect on our business, financial condition, and results of operations.

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

RISKS INHERENT IN AN INVESTMENT IN US

Our general partner’s liability regarding our obligations is limited.
Our general partner has included provisions in its and our contractual arrangements that limit its liability so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may, therefore, cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner otherwise would be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general
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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 379,519,983 common units outstanding as of December 31, 2023. Occidental currently holds 185,181,578 common units, representing 48.8% 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 8% of our common units as of December 31, 2023, from time to time. Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware
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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 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
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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, 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.
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 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.
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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 jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those
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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 1C.  Cybersecurity

Our cybersecurity program is designed to promote actions that protect our computer systems and networks, delivering safe, secure, and reliable operations. Our digital technology group is led by a dedicated Chief Information Security Officer (“CISO”). Our CISO has 15 years of experience as a chief information security officer, over four decades of experience in the energy industry, a degree in computer science, and manages a team at WES that is responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture, governance, and risk management. The CISO also leads WES’s Cybersecurity Council, which is a cross-functional internal team including members of WES senior management, that meets regularly to review current information-technology and cybersecurity issues and initiatives and to collaborate on key decisions. Additionally, the CISO provides quarterly reports to the Audit Committee of the Board of Directors. These reports include updates on WES’s cybersecurity risks and threats, the status of projects to strengthen our information security systems, assessments of the information security program, and the emerging threat landscape. Our cybersecurity program is regularly evaluated by internal and external experts with the results of those reviews reported to senior management and the Audit Committee. In addition, in our continuing commitment to cybersecurity education and preparedness, we also engage with industry peers, vendors, intelligence organizations, and law enforcement communities to evaluate and enhance the effectiveness of our information security policies and procedures.
Our business strategy, results of operations, and financial condition have not been materially affected by risks from cybersecurity threats, but we cannot provide assurance that they will not be materially affected in the future by such risks or any future material incidents. For more information on our cybersecurity related risks, see Risk Factors under Part I, Item 1A of this Form 10-K.

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Item 3.  Legal Proceedings

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 (along with its affiliates, collectively “Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas (the “Mont Belvieu JV Lawsuit”). In the Mont Belvieu JV Lawsuit, we sought a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between the Mont Belvieu JV (in which WGR was a 25% owner) and Enterprise related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas. Separately, on November 22, 2022, WGR filed suit against Enterprise in the District Court of Harris County, Texas (the “Whitethorn Lawsuit”). In the Whitethorn Lawsuit, we alleged, among other things, that Enterprise breached a contract related to its hydrocarbon trading activity that utilized the Whitethorn pipeline, and that Enterprise, as operator of the Whitethorn pipeline, breached its duties to act as a reasonable and prudent operator and for the sole benefit of the Whitethorn joint venture (in which WGR was a 20% owner). In response, Enterprise filed counterclaims related to alleged overpayments to WGR of approximately $12.0 million. In connection with the sales of our interests in both the Mont Belvieu JV and Whitethorn LLC on February 16, 2024, the Mont Belvieu Lawsuit and the Whitethorn Lawsuit were settled.
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 14, 2024, there were 24 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 1,226,875 and 9,479,648 units, respectively, remained available for future issuance as of December 31, 2023. 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 2023:
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, 2023
— $— — $627,807,310 
November 1-30, 2023
— — — 627,807,310 
December 1-31, 2023
— — — 627,807,310 
Total— — — 
______________________________________________________________________________________
(1)In February 2022, WES announced a $1.0 billion buyback 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, 2023, 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.
Discussion of 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.
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, 2023 (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 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, 2023, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
18 2 3 1 
Treating facilities38 3 — — 
Natural-gas processing plants/trains
24 3 — 3 
NGLs pipelines3 — — 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, 2023, included the following:

•On October 13, 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments). See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information.

•WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information.

•WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Net proceeds from this offering were used to repay borrowings under the RCF and for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information.

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•WES Operating redeemed the $213.1 million total principal amount outstanding of the Floating-Rate Senior Notes due 2023 at par value with cash on hand.

•WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases.

•In November 2023, WES operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion. See Liquidity and Capital Resources within this Item 7 for additional information.

•Our fourth-quarter 2023 per-unit distribution is unchanged from the third-quarter 2023 per-unit distribution of $0.575.

•The Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance. This Enhanced Distribution was paid, along with our regular first-quarter 2023 distribution, on May 15, 2023, to our unitholders of record at the close of business on May 1, 2023.

•We repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million.

•Natural-gas throughput attributable to WES totaled 4,432 MMcf/d for the year ended December 31, 2023, representing a 5% increase compared to the year ended December 31, 2022.

•Crude-oil and NGLs throughput attributable to WES totaled 652 MBbls/d for the year ended December 31, 2023, representing a 4% decrease compared to the year ended December 31, 2022.

•Produced-water throughput attributable to WES totaled 1,009 MBbls/d for the year ended December 31, 2023, representing a 21% increase compared to the year ended December 31, 2022.

•Gross margin was $2,341.2 million for the year ended December 31, 2023, representing a 4% increase compared to the year ended December 31, 2022. 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 $1.28 per Mcf for the year ended December 31, 2023, representing a 3% decrease compared to the year ended December 31, 2022.

•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 $2.48 per Bbl for the year ended December 31, 2023, representing a 1% increase compared to the year ended December 31, 2022.

•Adjusted gross margin for produced-water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.83 per Bbl for the year ended December 31, 2023, representing a 12% decrease compared to the year ended December 31, 2022.

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The following table provides additional information on throughput for the periods presented below:
Year Ended December 31,
20232022Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin1,635 1,470 11 %
DJ Basin1,322 1,331 (1)%
Powder River Basin120 33 NM
Equity investments466 483 (4)%
Other1,050 1,049 — %
Total throughput for natural-gas assets
4,593 4,366 5 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin214 198 8 %
DJ Basin71 82 (13)%
Powder River Basin5 — 100 %
Equity investments333 373 (11)%
Other42 37 14 %
Total throughput for crude-oil and NGLs assets
665 690 (4)%
Throughput for produced-water assets (MBbls/d)
Delaware Basin1,029 853 21 %
Total throughput for produced-water assets
1,029 853 21 %
_________________________________________________________________________________________
NM—Not meaningful

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, 2023, our West Texas and DJ Basin assets provided (i) 53% and 34%, respectively, of Total revenues and other, (ii) 40% and 32%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 65% and 21%, 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, 2023, 59% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% 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.

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For the year ended December 31, 2023, 95% 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.

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.

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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.

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.

Acquisitions and divestitures. In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF. For purposes of the discussion included in Results of Operations, the Powder River Basin complex includes our previously owned Hilight system and the assets acquired from Meritage.
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.
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments. We recognized long-lived asset and other impairments of $52.9 million and $20.6 million for the years ended December 31, 2023 and 2022, respectively. For a description of impairments recorded, 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.

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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,
thousands20232022
Total revenues and other (1)
$3,106,476 $3,251,721 
Equity income, net – related parties152,959 183,483 
Total operating expenses (1)
1,869,770 1,950,992 
Gain (loss) on divestiture and other, net(10,102)103,676 
Operating income (loss)1,379,563 1,587,888 
Interest expense(348,228)(333,939)
Gain (loss) on early extinguishment of debt15,378 91 
Other income (expense), net5,679 1,603 
Income (loss) before income taxes1,052,392 1,255,643 
Income tax expense (benefit)4,385 4,187 
Net income (loss)1,048,007 1,251,456 
Net income (loss) attributable to noncontrolling interests25,791 34,353 
Net income (loss) attributable to Western Midstream Partners, LP (2)
$1,022,216 $1,217,103 
_________________________________________________________________________________________
(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, 2023” refer to the comparison of the year ended December 31, 2023, to the year ended December 31, 2022.
Discussion of 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.
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Throughput
Year Ended December 31,
20232022Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation435 409 6 %
Processing3,692 3,474 6 %
Equity investments (1)
466 483 (4)%
Total throughput4,593 4,366 5 %
Throughput attributable to noncontrolling interests (2)
161 156 3 %
Total throughput attributable to WES for natural-gas assets
4,432 4,210 5 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation332 317 5 %
Equity investments (1)
333 373 (11)%
Total throughput665 690 (4)%
Throughput attributable to noncontrolling interests (2)
13 14 (7)%
Total throughput attributable to WES for crude-oil and NGLs assets
652 676 (4)%
Throughput for produced-water assets (MBbls/d)
Gathering and disposal1,029 853 21 %
Throughput attributable to noncontrolling interests (2)
20 17 18 %
Total throughput attributable to WES for produced-water assets
1,009 836 21 %
_________________________________________________________________________________________
(1)Represents our share of average throughput for investments accounted for under the equity method of accounting.
(2)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
Total throughput attributable to WES for natural-gas assets increased by 222 MMcf/d for the year ended December 31, 2023, primarily due to (i) higher volumes at the West Texas complex due to increased production in the area, (ii) higher volumes at the Powder River Basin complex as a result of the Meritage acquisition, (iii) higher volumes at the Springfield gas-gathering system due to new third-party production, (iv) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (v) higher volumes at the MIGC system. These increases were offset partially by (i) lower volumes at the Granger complex and Marcellus Interest systems due to production declines in the surrounding areas, (ii) 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, and (iii) lower volumes at the Mi Vida plant.

Crude-oil and NGLs assets
Total throughput attributable to WES for crude-oil and NGLs assets decreased by 24 MBbls/d for the year ended December 31, 2023, primarily due to (i) lower volumes on the Cactus II pipeline, which was sold in the fourth quarter of 2022, and (ii) lower volumes at the DJ Basin oil system resulting from production declines in the area. These decreases were offset partially by (i) increased volumes on the Whitethorn and Saddlehorn pipelines, (ii) higher volumes at the DBM oil system resulting from increased production in the area, and (iii) higher volumes on the Thunder Creek NGL pipeline which was acquired as part of the Meritage acquisition.

Produced-water assets
Total throughput attributable to WES for produced-water assets increased by 173 MBbls/d for the year ended December 31, 2023, due to higher production and new third-party connections brought online during 2023.
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Service Revenues
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
Service revenues – fee based$2,768,757 $2,602,053 6 %
Service revenues – product based191,727 249,692 (23)%
Total service revenues$2,960,484 $2,851,745 4 %

Service revenues – fee based
Service revenues – fee based increased by $166.7 million for the year ended December 31, 2023, primarily due to increases of (i) $114.1 million at the West Texas complex as a result of increased throughput and electricity-related rates billed to customers, (ii) $42.6 million at the Powder River Basin complex as a result of increased throughput attributable to the acquisition of Meritage (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7), (iii) $22.7 million at the DJ Basin complex due to increased deficiency fees on demand volumes and electricity-related rates billed to customers, (iv) $20.8 million and $12.1 million at the DBM water and DBM oil systems, respectively, due to increased throughput, partially offset by decreased deficiency fees, and (v) $5.6 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 compared to 2022, partially offset by decreased throughput and deficiency fees. These increases were partially offset by decreases of (i) $17.5 million at the Springfield system primarily due to decreased demand-fee revenue and a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by increased throughput, (ii) $12.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, and (iii) $12.1 million at the Chipeta complex due to decreased deficiency fees.

Service revenues – product based
Service revenues – product based decreased by $58.0 million for the year ended December 31, 2023, primarily due to decreases of (i) $22.0 million at the West Texas complex due to decreased average prices and lower product-related electricity reimbursements from customers, (ii) $14.5 million and $6.1 million at the DJ Basin and Powder River Basin complexes, respectively, due to decreased average prices, and (iii) $9.2 million and $4.3 million at the Red Desert and Granger complexes, respectively, due to decreased average prices and volumes sold.

Product Sales
Year Ended December 31,
thousands except percentages and per-unit amounts20232022Inc/
(Dec)
Natural-gas sales
$40,679 $129,187 (69)%
NGLs sales104,345 269,836 (61)%
Total Product sales$145,024 $399,023 (64)%
Per-unit gross average sales price:
Natural gas (per Mcf)$1.66 $5.66 (71)%
NGLs (per Bbl)27.89 40.51 (31)%

Natural-gas sales
Natural-gas sales decreased by $88.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $72.8 million at the West Texas complex due to decreased average prices, partially offset by higher volumes sold and (ii) $17.8 million at the Red Desert complex due to decreased average prices. These decreases were partially offset by an increase of $7.7 million at the DJ Basin complex as a result of contract mix, partially offset by decreased volumes sold and average prices.

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NGLs sales
NGLs sales decreased by $165.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $94.7 million at the West Texas complex due to changes in contract mix and decreased average prices, (ii) $22.9 million, $10.0 million, and $3.6 million at the Chipeta, Granger, and Red Desert complexes, respectively, due to decreased average prices and volumes sold, (iii) $22.9 million at the DJ Basin complex due to decreased average prices, partially offset by increased volumes sold, and (iv) $7.5 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

Equity Income, Net – Related Parties
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
Equity income, net – related parties$152,959 $183,483 (17)%

Equity income, net – related parties decreased by $30.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.7 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7) and (ii) $9.1 million, $6.0 million, and $3.5 million at TEP, Mont Belvieu JV, and Whitethorn, respectively.

Cost of Product and Operation and Maintenance Expenses
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
Residue purchases$32,515 $173,104 (81)%
NGLs purchases211,468 320,739 (34)%
Other(79,385)(72,943)(9)%
Cost of product164,598 420,900 (61)%
Operation and maintenance762,530 654,566 16 %
Total Cost of product and Operation and maintenance expenses$927,128 $1,075,466 (14)%

Residue purchases
Residue purchases decreased by $140.6 million for the year ended December 31, 2023, primarily due to decreases of (i) $84.1 million at the West Texas complex attributable to changes in contract mix during 2022 and lower average prices, (ii) $19.3 million at the Chipeta complex due to decreased volumes purchased and lower average prices, and (iii) $15.7 million and $8.2 million at the Red Desert and DJ Basin complexes, respectively, primarily due to lower average prices.

NGLs purchases
NGLs purchases decreased by $109.3 million for the year ended December 31, 2023, primarily due to decreases of (i) $61.5 million and $30.7 million at the West Texas and DJ Basin complexes, respectively, attributable to lower average prices and (ii) $7.7 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

Other items
Other items decreased by $6.4 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.5 million at the West Texas complex due to changes in imbalance positions, partially offset by higher offload costs, and (ii) $3.8 million and $2.9 million at the Red Desert complex and MIGC system, respectively, attributable to changes in imbalance positions. These decreases were partially offset by an increase of $16.9 million at the DJ Basin complex due to changes in imbalance positions.


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Operation and maintenance expense
Operation and maintenance expense increased by $108.0 million for the year ended December 31, 2023, primarily due to increases of (i) $35.8 million for equipment maintenance and repair expense, (ii) $27.7 million for salaries and wages costs, (iii) $11.8 million in utility expense, (iv) $9.6 million in land-related costs, (v) $8.9 million in higher equipment rental costs, (vi) $8.0 million in water-disposal costs, and (vii) $5.6 million attributable to higher contract labor and consulting expense.

Other Operating Expenses
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
General and administrative$232,632 $194,017 20 %
Property and other taxes56,458 78,559 (28)%
Depreciation and amortization600,668 582,365 3 %
Long-lived asset and other impairments
52,884 20,585 157 %
Total other operating expenses$942,642 $875,526 8 %

General and administrative expenses
General and administrative expenses increased by $38.6 million for the year ended December 31, 2023, primarily due to increases of (i) $16.2 million in personnel costs, including costs related to the acquisition of Meritage, (ii) $9.8 million in information technology costs, and (iii) $7.0 million in consulting and legal costs.

Property and other taxes
Property and other taxes decreased by $22.1 million for the year ended December 31, 2023, primarily due to decreases in the ad valorem property tax accrual during 2023 related to the finalization of 2022 assessments at the DJ Basin complex.

Depreciation and amortization expense
Depreciation and amortization expense increased by $18.3 million for the year ended December 31, 2023, primarily due to increases of (i) $10.1 million and $7.3 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service, (ii) $9.9 million at the Powder River Basin complex associated with the acquisition of Meritage, and (iii) $7.2 million related to depreciation for capitalized information technology implementation costs. These increases were offset partially by a decrease of $13.0 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2022.

Long-lived asset and other impairment expense
Long-lived asset and other impairment expense for the year ended December 31, 2023, was primarily due to a $52.1 million impairment for assets located in the Rockies.
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.
For further information on Long-lived asset and other impairment expense, 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.

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Interest Expense
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
Long-term and short-term debt
$(348,393)$(326,949)7 %
Finance lease liabilities(1,083)(414)162 %
Commitment fees and amortization of debt-related costs(12,395)(12,212)1 %
Capitalized interest13,643 5,636 142 %
Interest expense$(348,228)$(333,939)4 %

Interest expense increased by $14.3 million for the year ended December 31, 2023, primarily due to increases of (i) $34.7 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, (ii) $10.0 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, and (iii) $3.0 million primarily due to borrowings on the commercial paper program that was established during the fourth quarter of 2023. These increases were offset partially by decreases of (i) $14.6 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, (ii) $8.0 million due to higher capitalized interest, (iii) $6.7 million due to the redemption of the total principal amount outstanding of the Floating-Rate Senior Notes due 2023 during the first quarter of 2023, and (iv) $5.1 million due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 during the second quarter of 2022. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.

Other Income (Expense), Net
Year Ended December 31,
thousands except percentages20232022Inc/
(Dec)
Other income (expense), net$5,679 $1,603 NM

Other income (expense), net increased by $4.1 million for the year ended December 31, 2023, primarily due to interest income earned resulting from higher interest rates and cash and cash equivalent balances throughout 2023, partially offset by interest recorded in 2023 related to a sales tax audit.

Income Tax Expense (Benefit)

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. See Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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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, (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, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers.

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,
thousands20232022
Reconciliation of Gross margin to Adjusted gross margin
Total revenues and other$3,106,476 $3,251,721 
Less:
Cost of product164,598 420,900 
Depreciation and amortization600,668 582,365 
Gross margin2,341,210 2,248,456 
Add:
Distributions from equity investments194,273 250,050 
Depreciation and amortization600,668 582,365 
Less:
Reimbursed electricity-related charges recorded as revenues102,109 81,764 
Adjusted gross margin attributable to noncontrolling interests (1)
70,195 73,632 
Adjusted gross margin$2,963,847 $2,925,475 
_________________________________________________________________________________________
(1)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 analysis, 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 amounts20232022
Gross margin
Gross margin for natural-gas assets (1)
$1,738,125 $1,676,732 
Gross margin for crude-oil and NGLs assets (1)
368,444 346,406 
Gross margin for produced-water assets (1)
259,541 245,274 
Per-Mcf Gross margin for natural-gas assets (2)
1.04 1.05 
Per-Bbl Gross margin for crude-oil and NGLs assets (2)
1.52 1.38 
Per-Bbl Gross margin for produced-water assets (2)
0.69 0.79 
Adjusted gross margin
Adjusted gross margin for natural-gas assets
$2,067,528 $2,031,600 
Adjusted gross margin for crude-oil and NGLs assets
589,091 607,769 
Adjusted gross margin for produced-water assets
307,228 286,106 
Per-Mcf Adjusted gross margin for natural-gas assets (3)
1.28 1.32 
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (3)
2.48 2.46 
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.83 0.94 
_________________________________________________________________________________________
(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,
thousands20232022
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)$1,048,007 $1,251,456 
Add:
Distributions from equity investments194,273 250,050 
Non-cash equity-based compensation expense
32,005 27,783 
Interest expense348,228 333,939 
Income tax expense4,385 4,187 
Depreciation and amortization600,668 582,365 
Impairments52,884 20,585 
Other expense1,739 555 
Less:
Gain (loss) on divestiture and other, net(10,102)103,676 
Gain (loss) on early extinguishment of debt15,378 91 
Equity income, net – related parties152,959 183,483 
Other income6,976 1,648 
Adjusted EBITDA attributable to noncontrolling interests (1)
48,345 54,049 
Adjusted EBITDA$2,068,633 $2,127,973 
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities$1,661,334 $1,701,426 
Interest (income) expense, net348,228 333,939 
Accretion and amortization of long-term obligations, net
(8,151)(7,142)
Current income tax expense (benefit)3,341 2,188 
Other (income) expense, net(5,679)(1,603)
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 
Changes in assets and liabilities:
Accounts receivable, net78,346 116,296 
Accounts and imbalance payables and accrued liabilities, net68,019 7,812 
Other items, net(67,564)(34,791)
Adjusted EBITDA attributable to noncontrolling interests (1)
(48,345)(54,049)
Adjusted EBITDA$2,068,633 $2,127,973 
Cash flow information
Net cash provided by operating activities$1,661,334 $1,701,426 
Net cash used in investing activities(1,607,291)(218,237)
Net cash provided by (used in) financing activities(67,912)(1,398,532)
_________________________________________________________________________________________
(1)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,
thousands20232022
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities$1,661,334 $1,701,426 
Less:
Capital expenditures735,080 487,228 
Contributions to equity investments – related parties1,153 9,632 
Add:
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 
Free cash flow$964,205 $1,268,463 
Cash flow information
Net cash provided by operating activities$1,661,334 $1,701,426 
Net cash used in investing activities(1,607,291)(218,237)
Net cash provided by (used in) financing activities(67,912)(1,398,532)

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 $92.8 million for the year ended December 31, 2023, due to a $256.3 million decrease in cost of product. This amount was offset partially by (i) a $145.2 million decrease in total revenues and other and (ii) an $18.3 million increase in depreciation and amortization.

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) decreased by $203.4 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $113.8 million decrease in gain (loss) on divestiture and other, net, (iii) a $30.5 million decrease in equity income, net – related parties, and (iv) a $14.3 million increase in interest expense. These amounts were offset partially by (i) an $81.2 million decrease in total operating expenses and (ii) a $15.3 million increase in gain (loss) on early extinguishment of debt.

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 amounts20232022Inc/
(Dec)
Adjusted gross margin$2,963,847 $2,925,475 1 %
Per-Mcf Adjusted gross margin for natural-gas assets (1)
1.28 1.32 (3)%
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (1)
2.48 2.46 1 %
Per-Bbl Adjusted gross margin for produced-water assets (1)
0.83 0.94 (12)%
Adjusted EBITDA2,068,633 2,127,973 (3)%
Free cash flow964,205 1,268,463 (24)%
_________________________________________________________________________________________
(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 $38.4 million for the year ended December 31, 2023, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput, partially offset by decreased deficiency fees at the DBM water systems. These increases were partially offset by (i) a decrease in distributions from Cactus II, which was sold in the fourth quarter of 2022, (ii) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue, partially offset by increased throughput at the Springfield system, (iii) decreased deficiency fees at the Chipeta complex, (iv) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, (v) a decrease in distributions from Ranch Westex, which was acquired in the third quarter of 2022 and is included in the West Texas complex subsequent to the acquisition, and (vi) decreased throughput at the Granger complex.
Per-Mcf Adjusted gross margin for natural-gas assets decreased by $0.04 for the year ended December 31, 2023, primarily due to (i) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue at the Springfield system, and (ii) decreased deficiency fees at the Chipeta complex. These decreases were partially offset by (i) increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, and (ii) increased deficiency fees at the DJ Basin complex.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.02 for the year ended December 31, 2023, primarily due to (i) decreases in throughput and distributions from Cactus II, which was sold in the fourth quarter of 2022 and had lower-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 2023 as compared to 2022, partially offset by decreased throughput and deficiency fees at the DJ Basin oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (iii) an increase in distributions from FRP. These increases were partially offset by decreases in distributions from Whitethorn LLC, Mont Belvieu JV, and Saddlehorn.
Per-Bbl Adjusted gross margin for produced-water assets decreased by $0.11 for the year ended December 31, 2023, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2023, and lower deficiency fee revenues.

Adjusted EBITDA. Adjusted EBITDA decreased by $59.3 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $108.0 million increase in operation and maintenance expenses, (iii) a $55.8 million decrease in distributions from equity investments, and (iv) a $34.4 million increase in general and administrative expenses excluding non-cash equity-based compensation expense. These amounts were offset partially by (i) a $256.2 million decrease in cost of product (net of lower of cost or market inventory adjustments), and (ii) a $22.1 million decrease in property and other taxes.

Free cash flow. Free cash flow decreased by $304.3 million for the year ended December 31, 2023, primarily due to (i) a $247.9 million increase in capital expenditures, (ii) a $40.1 million decrease in net cash provided by operating activities, and (iii) a $24.8 million decrease in distributions from equity investments in excess of cumulative earnings. These amounts were offset partially by an $8.5 million decrease in contributions to equity investments.
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See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

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 producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude-oil, natural-gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. 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, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude-oil daily settlement prices during 2022 ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022, and prices during the year ended December 31, 2023, ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023. Similar disruptions could occur as a consequence of the current conflict in the Middle East. The extent and duration of commodity-price volatility, and the associated direct and indirect impact on our business, cannot be predicted. To address the risks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.
Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can have a significant impact on the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise.

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.


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Impact of inflation and supply-chain disruptions. The U.S. economy has recently experienced 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 continued bottlenecks and disruptions 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 steel products, automation components, power supply, 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.

Impact of interest rates. Short- and long-term interest rates can be volatile resulting in immediate changes to interest expense on RCF borrowings, commercial paper borrowings, and other floating-rate debt securities. Any future increases in interest rates likely will result in additional increases in financing costs. 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, 2023, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, our commercial paper program, 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 be determined by the Board on a quarterly basis. 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. The Board declared a cash distribution to unitholders for the fourth quarter of 2023 of $0.575 per unit, or $223.4 million in the aggregate. The cash distribution was paid on February 13, 2024, to our unitholders of record at the close of business on February 1, 2024.
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 thresholds (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 April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance, which was paid in conjunction with our regular first-quarter 2023 distribution on May 15, 2023.

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In 2022, we announced a common-unit buyback program of up to $1.25 billion through December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the year ended December 31, 2023, we repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. The units were canceled immediately upon receipt. As of December 31, 2023, we had an authorized amount of $627.8 million remaining under the program.
For the year ended December 31, 2024, capital expenditures are expected to range between $700.0 million to $850.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Total-year capital expenditures guidance includes capital expenditures attributable to (i) a portion of Mentone Train III, which is expected to be complete and in-service at the end of the first quarter of 2024, (ii) a portion of the North Loving plant, a new 250 MMcf/d cryogenic processing plant in the North Loving area of our West Texas complex that was sanctioned in May 2023, and (iii) additional expansion capital needed to support new commercial activity.
Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or financing 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 and the amounts involved may be material. 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, 2023, we had a $311.6 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 outstanding commercial paper borrowings being classified as short-term debt on the consolidated balance sheet. As of December 31, 2023, there was $1.4 billion in effective borrowing capacity under the RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for our commercial paper program. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures 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,
thousands20232022
Acquisitions$877,746 $40,127 
Capital expenditures (1)
735,080 487,228 
Capital incurred (1)
752,338 534,342 
_________________________________________________________________________________________
(1)For the years ended December 31, 2023 and 2022, included $13.6 million and $5.6 million, respectively, of capitalized interest.

Acquisitions for the year ended December 31, 2023, include the acquisition of Meritage. Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex. See Items Affecting the Comparability of Our Financial Results within this Item 7.
Capital expenditures increased by $247.9 million for the year ended December 31, 2023, primarily due to increases of (i) $130.4 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III and engineering and equipment milestone payments for the North Loving Plant, and pipeline projects, (ii) $55.0 million at the DBM water systems due to construction of additional water-disposal wells and facilities, pipeline build-out, and replacement projects, (iii) $39.0 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects, (iv) $10.0 million related to the acquisition of Meritage, (v) $9.9 million at the DJ Basin oil system due to an increase in pipeline projects, and (vi) $8.3 million at the DJ Basin complex due to an increase in well connection and pipeline projects.

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Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities:
Year Ended December 31,
thousands20232022
Net cash provided by (used in):
Operating activities$1,661,334 $1,701,426 
Investing activities(1,607,291)(218,237)
Financing activities(67,912)(1,398,532)
Net increase (decrease) in cash and cash equivalents$(13,869)$84,657 

Operating activities. Net cash provided by operating activities decreased for the year ended December 31, 2023, primarily due to (i) lower distributions from equity investments, (ii) higher interest expense, and (iii) lower cash operating income. These decreases were partially offset by the impact of changes in assets and liabilities. 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, 2023, primarily included the following:
•$877.7 million of cash paid, net of cash received, for the acquisition of Meritage;

•$735.1 million of capital expenditures, primarily related to expansion, construction, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system;

•$32.3 million of increases to materials and supplies inventory; and

•$39.1 million of distributions received from equity investments in excess of cumulative earnings.

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.

Financing activities. Net cash used in financing activities for the year ended December 31, 2023, primarily included the following:
•$1,495.0 million of repayments of outstanding borrowings under the RCF;

•$1,008.9 million of distributions paid to WES unitholders and noncontrolling interest owners;

•$259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases;

•$213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value;

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•$134.6 million of unit repurchases;

•$1,120.0 million of borrowings under the RCF, which were used for general partnership purposes;

•$740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes;

•$609.9 million of net borrowings under the commercial paper program, which were used for general partnership purposes; and

•$592.8 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes.

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.

Debt and credit facilities. As of December 31, 2023, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $346.3 million in 2024. In addition, we have no senior note borrowings due within the next year and, as of December 31, 2023, have $1.4 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for WES Operating’s commercial paper program.
During the year ended December 31, 2023, WES Operating (i) completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029, (ii) completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033, (iii) entered into an amendment to our RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date, (iv) entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion (WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings), (v) purchased and retired $276.7 million of certain of its senior notes via open-market repurchases, and (vi) redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand.
In May 2023, Fitch Ratings upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” WES Operating’s senior unsecured debt ratings are now investment grade at Standard and Poor’s, Moody’s Investors Services, and Fitch Ratings. As a result of the upgrade, annualized borrowing costs will decrease by $6.9 million on WES Operating’s senior notes that are subject to effective interest-rate adjustments from a change in credit rating.
For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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Finance lease liabilities. WES has finance leases with third parties for equipment, vehicles, and an NGL pipeline in Wyoming. As of December 31, 2023, we have future finance-lease payments of $7.7 million for 2024 and a total of $35.0 million in years thereafter.

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 property, 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, 2023, we expect to incur asset retirement costs of $7.6 million in 2024 and a total of $359.2 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Operating leases. We have entered into operating leases for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors. As of December 31, 2023, we have future operating-lease payments of $11.6 million in 2024 and a total of $67.7 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.

Offload commitments. We have entered into offload agreements with third parties providing firm-processing capacity through 2025. As of December 31, 2023, we have future minimum payments under offload agreements totaling $7.7 million for 2024 and a total of $3.4 million in years thereafter.

Pipeline commitments. We have entered into transportation contracts with volume commitments on multiple pipelines through 2033. As of December 31, 2023, we have estimated future minimum-volume-commitment fees totaling $11.3 million for 2024, and a total of $67.5 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 contractual rights to request adequate assurance of performance.
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,
thousands202320222021
Net income (loss) attributable to WES$1,022,216 $1,217,103 $916,292 
Limited partner interest in WES Operating not held by WES (1)
20,922 24,899 18,765 
General and administrative expenses (2)
2,943 2,656 2,932 
Other income (expense), net(275)(45)(11)
Income taxes6 7 9 
Net income (loss) attributable to WES Operating$1,045,812 $1,244,620 $937,987 
_________________________________________________________________________________________
(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,
thousands202320222021
WES net cash provided by operating activities$1,661,334 $1,701,426 $1,766,852 
General and administrative expenses (1)
2,943 2,656 2,932 
Non-cash equity-based compensation expense
(581)(570)6,912 
Changes in working capital(15,226)(9,341)(11,315)
Other income (expense), net(275)(45)(11)
Income taxes6 7 9 
WES Operating net cash provided by operating activities$1,648,201 $1,694,133 $1,765,379 
WES net cash provided by (used in) financing activities$(67,912)$(1,398,532)$(1,752,237)
Distributions to WES unitholders (2)
978,430 735,755 533,758 
Distributions to WES from WES Operating (3)
(1,119,367)(1,219,635)(734,034)
Increase (decrease) in outstanding checks(52)103 (68)
Unit repurchases134,602 487,590 217,465 
Other15,472 9,326 4,336 
WES Operating net cash provided by (used in) financing activities$(58,827)$(1,385,393)$(1,730,780)
_________________________________________________________________________________________
(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 throughput forecasts or changes in future development plans by producers, to the extent they affect our operations, may trigger 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 throughput 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.

82
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 an other-than-temporary 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 $52.9 million for the year ended December 31, 2023, and $20.6 million (which includes an other-than-temporary impairment expense of an equity investment) for the year ended December 31, 2022. 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, 2023, 2022, and 2021.

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.

Fair value estimates in business combination accounting. Business combination accounting requires that assets and liabilities be recorded at their estimated fair value in connection with the initial recognition of the transaction. Estimating the fair value of assets and liabilities in connection with business combination accounting requires management to make estimates, assumptions and judgments, and in some cases management may also utilize third-party specialists to assist and advise on those estimates.
In order to estimate the fair value of acquired assets and assumed liabilities, we utilize widely accepted valuation techniques that include market and discounted cash flow approaches. These approaches utilize assumptions that include, but are not limited to, estimated future cash flows, discount rates applied to estimated future cash flows, and estimated asset replacement costs. While we believe we have made reasonable assumptions to estimate the fair value, these assumptions are inherently uncertain.
The acquisition-date fair value recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. See Note 3—Acquisitions and Divestitures 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.

83
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, 2023, 95% 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 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 increased its target range seven times for the federal funds rate in 2022 and increased its target range four times during the year ended December 31, 2023. Any future increases in the federal funds rate likely will result in an increase in financing costs. As of December 31, 2023, WES Operating had (i) no outstanding borrowings under the RCF that bear interest at a rate based on the Secured Overnight Financing Rate (“SOFR”) or an alternative base rate at WES Operating’s option and (ii) $613.9 million of outstanding commercial paper borrowings. While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings at December 31, 2023, it would impact the fair value of the senior notes.
Additional short-term or 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
85
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, 2023. 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, 2023. The Partnership acquired Meritage Midstream Services II, LLC, in October 2023 and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2023, Meritage Midstream Services II, LLC’s internal control over financial reporting associated with total assets of $1.01 billion and total revenues of $41.4 million included in the consolidated financial statements of Western Midstream Partners, LP and subsidiaries as of and for the year ended December 31, 2023.
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, 2023.

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 21, 2024

86
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, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023, 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 21, 2024 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
87
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 21, 2024

88
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, 2023, 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, 2023, 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, 2023 and 2022, 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, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 21, 2024 expressed an unqualified opinion on those consolidated financial statements.

The Partnership acquired Meritage Midstream Services II, LLC during 2023, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2023, Meritage Midstream Services II, LLC’s internal control over financial reporting associated with total assets of $1.01 billion and total revenues of $41.4 million included in the consolidated financial statements of the Partnership as of and for the year ended December 31, 2023. Our audit of internal control over financial reporting of the Partnership also excluded an evaluation of the internal control over financial reporting of Meritage Midstream Services II, LLC.

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.


89
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 21, 2024
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands except per-unit amounts202320222021
Revenues and other
Service revenues – fee based$2,768,757 $2,602,053 $2,462,835 
Service revenues – product based191,727 249,692 122,584 
Product sales145,024 399,023 290,947 
Other968 953 789 
Total revenues and other (1)
3,106,476 3,251,721 2,877,155 
Equity income, net – related parties152,959 183,483 204,645 
Operating expenses
Cost of product164,598 420,900 322,285 
Operation and maintenance762,530 654,566 581,300 
General and administrative232,632 194,017 195,549 
Property and other taxes56,458 78,559 64,267 
Depreciation and amortization600,668 582,365 551,629 
Long-lived asset and other impairments (2)
52,884 20,585 30,543 
Total operating expenses (3)
1,869,770 1,950,992 1,745,573 
Gain (loss) on divestiture and other, net(10,102)103,676 44 
Operating income (loss)1,379,563 1,587,888 1,336,271 
Interest expense(348,228)(333,939)(376,512)
Gain (loss) on early extinguishment of debt15,378 91 (24,944)
Other income (expense), net5,679 1,603 (623)
Income (loss) before income taxes1,052,392 1,255,643 934,192 
Income tax expense (benefit)4,385 4,187 (9,807)
Net income (loss)1,048,007 1,251,456 943,999 
Net income (loss) attributable to noncontrolling interests25,791 34,353 27,707 
Net income (loss) attributable to Western Midstream Partners, LP$1,022,216 $1,217,103 $916,292 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Partners, LP$1,022,216 $1,217,103 $916,292 
General partner interest in net (income) loss(23,684)(27,541)(19,815)
Limited partners’ interest in net income (loss) (4)
998,532 1,189,562 896,477 
Net income (loss) per common unit – basic (4)
$2.61 $3.01 $2.18 
Net income (loss) per common unit – diluted (4)
$2.60 $3.00 $2.18 
Weighted-average common units outstanding – basic (4)
383,028 394,951 411,309 
Weighted-average common units outstanding – diluted (4)
384,408 396,236 412,022 
_________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.8 billion, $1.8 billion, and $1.6 billion for the years ended December 31, 2023, 2022, and 2021, respectively. See Note 6.
(2)See Note 7 and Note 9.
(3)Total operating expenses includes related-party amounts of $(68.0) million, $(18.0) million, and $86.2 million for the years ended December 31, 2023, 2022, and 2021, respectively, all primarily related to changes in imbalance positions. See Note 6.
(4)See Note 5.
See accompanying Notes to Consolidated Financial Statements.
91
WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20232022
ASSETS
Current assets
Cash and cash equivalents$272,787 $286,656 
Accounts receivable, net666,637 554,263 
Other current assets52,986 59,506 
Total current assets992,410 900,425 
Property, plant, and equipment
Cost14,945,431 13,365,593 
Less accumulated depreciation5,290,415 4,823,993 
Net property, plant, and equipment9,655,016 8,541,600 
Goodwill4,783 4,783 
Other intangible assets681,408 713,075 
Equity investments904,535 944,696 
Other assets (1)
233,455 167,049 
Total assets (2)
$12,471,607 $11,271,628 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$362,451 $360,562 
Short-term debt
617,748 215,780 
Accrued ad valorem taxes61,285 72,875 
Accrued liabilities262,572 254,640 
Total current liabilities1,304,056 903,857 
Long-term liabilities
Long-term debt
7,283,556 6,569,582 
Deferred income taxes15,468 14,424 
Asset retirement obligations359,185 290,021 
Other liabilities480,212 385,629 
Total long-term liabilities
8,138,421 7,259,656 
Total liabilities (3)
9,442,477 8,163,513 
Equity and partners’ capital
Common units (379,519,983 and 384,070,984 units issued and outstanding at December 31, 2023 and 2022, respectively)
2,894,231 2,969,604 
General partner units (9,060,641 units issued and outstanding at December 31, 2023 and 2022)
3,193 2,105 
Total partners’ capital2,897,424 2,971,709 
Noncontrolling interests131,706 136,406 
Total equity and partners’ capital3,029,130 3,108,115 
Total liabilities, equity, and partners’ capital$12,471,607 $11,271,628 
________________________________________________________________________________________
(1)Other assets includes $5.7 million and $6.5 million of NGLs line-fill inventory as of December 31, 2023 and 2022, respectively. Other assets also includes $96.3 million and $60.4 million of materials and supplies inventory as of December 31, 2023 and 2022, respectively.
(2)Total assets includes related-party amounts of $1.3 billion as of December 31, 2023 and 2022, which includes related-party Accounts receivable, net of $358.1 million and $313.9 million as of December 31, 2023 and 2022, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $378.8 million and $312.3 million as of December 31, 2023 and 2022, respectively. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
92
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, 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 (1)
(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 (1)
(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 
Net income (loss)998,532 23,684 25,791 1,048,007 
Distributions to Chipeta noncontrolling interest owner— — (7,641)(7,641)
Distributions to noncontrolling interest owner of WES Operating— — (22,850)(22,850)
Distributions to Partnership unitholders(955,834)(22,596)— (978,430)
Unit repurchases (1)
(134,602)— — (134,602)
Equity-based compensation expense
32,005 — — 32,005 
Other(15,474)— — (15,474)
Balance at December 31, 2023$2,894,231 $3,193 $131,706 $3,029,130 
_________________________________________________________________________________________
(1)See Note 5.

See accompanying Notes to Consolidated Financial Statements.
93
WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202320222021
Cash flows from operating activities
Net income (loss)$1,048,007 $1,251,456 $943,999 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization600,668 582,365 551,629 
Long-lived asset and other impairments
52,884 20,585 30,543 
Non-cash equity-based compensation expense
32,005 27,783 27,676 
Deferred income taxes1,044 1,999 (9,770)
Accretion and amortization of long-term obligations, net
8,151 7,142 7,635 
Equity income, net – related parties(152,959)(183,483)(204,645)
Distributions from equity-investment earnings – related parties
155,169 186,153 213,516 
(Gain) loss on divestiture and other, net10,102 (103,676)(44)
(Gain) loss on early extinguishment of debt(15,378)(91)24,944 
Other442 510 260 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(78,346)(116,296)16,366 
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(68,019)(7,812)114,887 
Change in other items, net67,564 34,791 49,856 
Net cash provided by operating activities1,661,334 1,701,426 1,766,852 
Cash flows from investing activities
Capital expenditures(735,080)(487,228)(313,674)
Acquisitions from third parties(877,746)(40,127)— 
Contributions to equity investments – related parties(1,153)(9,632)(4,435)
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 41,385 
Proceeds from the sale of assets to related parties— 200 — 
Proceeds from the sale of assets to third parties(87)264,121 8,102 
(Increase) decrease in materials and supplies inventory and other(32,329)(9,468)11,084 
Net cash used in investing activities(1,607,291)(218,237)(257,538)
Cash flows from financing activities
Borrowings, net of debt issuance costs 2,448,733 1,389,010 480,000 
Repayments of debt (1,967,928)(1,518,548)(1,432,966)
Commercial paper borrowings (repayments), net
609,916 — — 
Increase (decrease) in outstanding checks3,516 2,206 (21,631)
Distributions to Partnership unitholders (1)
(978,430)(735,755)(533,758)
Distributions to Chipeta noncontrolling interest owner(7,641)(10,736)(9,117)
Distributions to noncontrolling interest owner of WES Operating(22,850)(24,898)(14,984)
Net contributions from (distributions to) related parties— 1,423 8,533 
Unit repurchases (1)
(134,602)(487,590)(217,465)
Other(18,626)(13,644)(10,849)
Net cash provided by (used in) financing activities(67,912)(1,398,532)(1,752,237)
Net increase (decrease) in cash and cash equivalents(13,869)84,657 (242,923)
Cash and cash equivalents at beginning of period286,656 201,999 444,922 
Cash and cash equivalents at end of period$272,787 $286,656 $201,999 
Supplemental disclosures
Interest paid, net of capitalized interest$326,948 $355,363 $375,007 
Income taxes paid (reimbursements received)4,131 912 938 
Accrued capital expenditures99,610 82,353 35,240 
_________________________________________________________________________________________
(1)Includes related-party amounts. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
94
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)
Western Midstream Operating, 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, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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
95
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 21, 2024
96
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands 202320222021
Revenues and other
Service revenues – fee based$2,768,757 $2,602,053 $2,462,835 
Service revenues – product based191,727 249,692 122,584 
Product sales145,024 399,023 290,947 
Other968 953 789 
Total revenues and other (1)
3,106,476 3,251,721 2,877,155 
Equity income, net – related parties152,959 183,483 204,645 
Operating expenses
Cost of product164,598 420,900 322,285 
Operation and maintenance762,530 654,566 581,300 
General and administrative229,689 191,361 192,617 
Property and other taxes56,458 78,559 64,267 
Depreciation and amortization600,668 582,365 551,629 
Long-lived asset and other impairments (2)
52,884 20,585 30,543 
Total operating expenses (3)
1,866,827 1,948,336 1,742,641 
Gain (loss) on divestiture and other, net(10,102)103,676 44 
Operating income (loss)1,382,506 1,590,544 1,339,203 
Interest expense(348,228)(333,939)(376,512)
Gain (loss) on early extinguishment of debt15,378 91 (24,944)
Other income (expense), net5,404 1,558 (634)
Income (loss) before income taxes1,055,060 1,258,254 937,113 
Income tax expense (benefit)4,379 4,180 (9,816)
Net income (loss)1,050,681 1,254,074 946,929 
Net income (loss) attributable to noncontrolling interest4,869 9,454 8,942 
Net income (loss) attributable to Western Midstream Operating, LP$1,045,812 $1,244,620 $937,987 
________________________________________________________________________________________
(1)Total revenues and other includes $1.8 billion, $1.8 billion, and $1.6 billion for the years ended December 31, 2023, 2022, and 2021, respectively. See Note 6.
(2)See Note 7 and Note 9.
(3)Total operating expenses includes related-party amounts of $(64.7) million, $(15.0) million, and $89.0 million for the years ended December 31, 2023, 2022, and 2021, respectively, all primarily related to changes in imbalance positions. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
97
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20232022
ASSETS
Current assets
Cash and cash equivalents$268,184 $286,101 
Accounts receivable, net666,615 554,263 
Other current assets50,468 57,291 
Total current assets985,267 897,655 
Property, plant, and equipment
Cost14,945,431 13,365,593 
Less accumulated depreciation5,290,415 4,823,993 
Net property, plant, and equipment9,655,016 8,541,600 
Goodwill4,783 4,783 
Other intangible assets681,408 713,075 
Equity investments904,535 944,696 
Other assets (1)
231,644 166,450 
Total assets (2)
$12,462,653 $11,268,259 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$392,752 $404,468 
Short-term debt
617,748 215,780 
Accrued ad valorem taxes61,285 72,875 
Accrued liabilities203,461 197,289 
Total current liabilities1,275,246 890,412 
Long-term liabilities
Long-term debt
7,283,556 6,569,582 
Deferred income taxes15,468 14,424 
Asset retirement obligations359,185 290,021 
Other liabilities476,844 383,713 
Total long-term liabilities
8,135,053 7,257,740 
Total liabilities (3)
9,410,299 8,148,152 
Equity and partners’ capital
Common units (318,675,578 units issued and outstanding at December 31, 2023, and 2022)
3,027,031 3,092,012 
Total partners’ capital3,027,031 3,092,012 
Noncontrolling interest25,323 28,095 
Total equity and partners’ capital3,052,354 3,120,107 
Total liabilities, equity, and partners’ capital$12,462,653 $11,268,259 
_________________________________________________________________________________________
(1)Other assets includes $5.7 million and $6.5 million of NGLs line-fill inventory as of December 31, 2023 and 2022, respectively. Other assets also includes $96.3 million and $60.4 million of materials and supplies inventory as of December 31, 2023 and 2022, respectively.
(2)Total assets includes related-party amounts of $1.3 billion as of December 31, 2023 and 2022, which includes related-party Accounts receivable, net of $358.1 million and $313.9 million as of December 31, 2023 and 2022, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $409.5 million and $356.0 million as of December 31, 2023 and 2022, 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, 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 
Net income (loss)1,045,812 4,869 1,050,681 
Distributions to Chipeta noncontrolling interest owner— (7,641)(7,641)
Distributions to WES Operating unitholders(1,142,217)— (1,142,217)
Contributions of equity-based compensation from WES
31,424 — 31,424 
Balance at December 31, 2023
$3,027,031 $25,323 $3,052,354 
See accompanying Notes to Consolidated Financial Statements.
99
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202320222021
Cash flows from operating activities
Net income (loss)$1,050,681 $1,254,074 $946,929 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization600,668 582,365 551,629 
Long-lived asset and other impairments
52,884 20,585 30,543 
Non-cash equity-based compensation expense
31,424 27,213 34,588 
Deferred income taxes1,044 1,999 (9,770)
Accretion and amortization of long-term obligations, net
8,151 7,142 7,635 
Equity income, net – related parties(152,959)(183,483)(204,645)
Distributions from equity-investment earnings – related parties
155,169 186,153 213,516 
(Gain) loss on divestiture and other, net10,102 (103,676)(44)
(Gain) loss on early extinguishment of debt(15,378)(91)24,944 
Other442 510 260 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(78,324)(116,296)(28,965)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(83,332)(17,189)150,055 
Change in other items, net67,629 34,827 48,704 
Net cash provided by operating activities1,648,201 1,694,133 1,765,379 
Cash flows from investing activities
Capital expenditures(735,080)(487,228)(313,674)
Acquisitions from third parties(877,746)(40,127)— 
Contributions to equity investments – related parties(1,153)(9,632)(4,435)
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 41,385 
Proceeds from the sale of assets to related parties— 200 — 
Proceeds from the sale of assets to third parties(87)264,121 8,102 
(Increase) decrease in materials and supplies inventory and other(32,329)(9,468)11,084 
Net cash used in investing activities(1,607,291)(218,237)(257,538)
Cash flows from financing activities
Borrowings, net of debt issuance costs2,448,733 1,389,010 480,000 
Repayments of debt (1,967,928)(1,518,548)(1,432,966)
Commercial paper borrowings (repayments), net
609,916 — — 
Increase (decrease) in outstanding checks3,464 2,309 (21,699)
Distributions to WES Operating unitholders (1)
(1,142,217)(1,244,533)(749,018)
Distributions to Chipeta noncontrolling interest owner(7,641)(10,736)(9,117)
Net contributions from (distributions to) related parties— 1,423 8,533 
Other(3,154)(4,318)(6,513)
Net cash provided by (used in) financing activities(58,827)(1,385,393)(1,730,780)
Net increase (decrease) in cash and cash equivalents(17,917)90,503 (222,939)
Cash and cash equivalents at beginning of period286,101 195,598 418,537 
Cash and cash equivalents at end of period$268,184 $286,101 $195,598 
Supplemental disclosures
Interest paid, net of capitalized interest$326,948 $355,363 $375,007 
Income taxes paid (reimbursements received)4,131 912 938 
Accrued capital expenditures99,610 82,353 35,240 
________________________________________________________________________________________
(1)Includes related-party amounts. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
100
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 its customers under certain contracts. As of December 31, 2023, the Partnership’s assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
18 2 3 1 
Treating facilities38 3 — — 
Natural-gas processing plants/trains
24 3 — 3 
NGLs pipelines3 — — 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.
101
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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 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.
102
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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, 2023 (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.

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).

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.
103
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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. As such, debt fair values as presented in Note 13 use Level-2 inputs.
The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, and outstanding borrowings on the revolving credit facility and commercial paper program 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, 2023, 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, 2023 and 2022.

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 generally 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, 2023, imbalance receivables and payables were $5.1 million and $7.2 million, respectively. As of December 31, 2022, imbalance receivables and payables were $32.7 million and $32.5 million, respectively. Net changes in imbalance receivables and payables are reported in Cost of product in the consolidated statements of operations.

Inventory. The cost of NGLs inventory is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or net realizable value. NGLs inventory is reported in Other current assets and NGLs line-fill inventory is reported in Other assets on the consolidated balance sheets. Materials and supplies inventory is valued at weighted-average cost, reviewed periodically for obsolescence, and assessed for impairment together with any associated property, plant, and equipment and other intangible assets. Materials and supplies inventory is reported in Other assets on the consolidated balance sheets.
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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, 2023, 2022, and 2021.

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.
In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The standard improves reportable segment disclosure requirements for public business entities primarily through enhanced disclosures about significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit (referred to as the “significant expense principle”). The standard will become effective for the Partnership for the fiscal year 2024 annual financial statements and interim financial statements thereafter and will be applied retrospectively for all prior periods presented in the financial statements, with early adoption permitted. The Partnership plans to adopt the standard when it becomes effective beginning with the fiscal year 2024 annual financial statements. The Partnership is currently evaluating the impact this guidance will have on disclosures in the Notes to Consolidated Financial Statements. This standard will have no impact to the Partnership’s financial statements, but will result in additional disclosure.
105
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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. 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.
106
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation, and disposal of natural gas, NGLs, condensate, crude oil, and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same per-unit rate over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed at the completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties. Timing differences between amounts recognized in Service revenues – fee based and the amounts billed to customer are recognized as contract assets or contract liabilities, and are amortized over the related contract period.
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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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 $24.6 million, $21.8 million, and $23.7 million for the years ended December 31, 2023, 2022, and 2021, 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, 2023 or 2022.

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, 2023 or 2022.

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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes revenue from contracts with customers:
Year Ended December 31,
thousands202320222021
Revenue from customers
Service revenues – fee based$2,768,757 $2,602,053 $2,283,584 
Service revenues – product based191,727 249,692 122,584 
Product sales145,024 399,023 290,947 
Total revenue from customers3,105,508 3,250,7682,697,115
Revenue from other than customers
Lease revenue (1)
— — 179,251 
Other968 953 789 
Total revenues and other$3,106,476 $3,251,721 $2,877,155 
_________________________________________________________________________________________
(1)Includes fixed- and variable-lease revenue from an operating and maintenance agreement entered into with Occidental. See Note 6 and Note 14.

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $661.6 million and $545.0 million as of December 31, 2023 and 2022, respectively.
Contract assets primarily relate to (i) revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees and (ii) accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed. The following table summarizes activity related to contract assets from contracts with customers:
Year Ended December 31,
thousands20232022
Contract assets balance at beginning of year
$22,561 $22,557 
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period(6,678)(7,683)
Additional estimated revenues recognized9,487 5,531 
Cumulative catch-up adjustment for change in estimated consideration13,922 2,156 
Contract assets balance at end of year
$39,292 $22,561 
December 31,
thousands20232022
Other current assets$9,595 $3,381 
Other assets29,697 19,180 
Total contract assets from contracts with customers$39,292 $22,561 

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
thousands20232022
Contract liabilities balance at beginning of year
$369,285 $313,146 
Cash received or receivable, excluding revenues recognized during the period84,336 71,097 
Revenues recognized that were included in the contract liability balance at the beginning of the period(15,572)(16,158)
Cumulative catch-up adjustment for change in estimated consideration(4,363)1,200 
Amounts acquired with the acquisition of Meritage (1)
11,813 — 
Contract liabilities balance at end of year
$445,499 $369,285 
December 31,
thousands20232022
Accrued liabilities$16,866 $20,903 
Other liabilities428,633 348,382 
Total contract liabilities from contracts with customers$445,499 $369,285 
_________________________________________________________________________________________
(1)See Note 3.

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, 2023, 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
2024$1,145,612 
20251,097,142 
20261,019,676 
2027927,846 
2028665,106 
Thereafter2,127,654 
Total$6,983,036 

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. ACQUISITIONS AND DIVESTITURES

Meritage. On October 13, 2023, the Partnership closed on the acquisition of Meritage Midstream Services II, LLC (“Meritage”) for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from the Partnership’s $600.0 million senior note issuance in September 2023 (see Note 13) and borrowings on the senior unsecured revolving credit facility (“RCF”). The $877.7 million included as Acquisitions from third parties in the consolidated statements of cash flows includes the cash purchase price adjusted for working capital and certain customary post-closing adjustments, and reduced by the $38.4 million of cash acquired (as presented in the table below).
The assets acquired, located in Converse, Campbell, and Johnson counties, Wyoming, include approximately 1,500 miles of high- and low-pressure natural-gas gathering pipelines, approximately 380 MMcf/d of natural-gas processing capacity, and the Thunder Creek NGL pipeline, which is a 120 mile, 38 MBbls/d FERC-regulated NGL pipeline that connects to the processing facility. The acquisition expands the Partnership’s existing Powder River Basin asset base, increasing total natural-gas processing capacity in that region to 440 MMcf/d.
The Meritage acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Meritage acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Meritage acquisition were included in the Partnership’s consolidated statements of operations beginning on the acquisition date in the fourth quarter of 2023. For the year ended December 31, 2023, acquisition-related transaction costs of $6.1 million, consisting primarily of third-party consulting and legal fees, are included in General and administrative expenses in the consolidated statements of operations.
The following is the preliminary acquisition-date fair value as of December 31, 2023, for the assets acquired and liabilities assumed in the Meritage acquisition. The preliminary fair values are subject to change within the measurement period (up to one year from the acquisition date), pending a final determination of the fair value of certain customary post-closing working capital adjustments.

thousands
Assets acquired:
Cash and cash equivalents$38,412 
Accounts receivable, net34,060 
Other current assets1,980 
Property, plant, and equipment925,905 
Other assets6,498 
Total assets acquired1,006,855 
Liabilities assumed:
Accounts payable and accrued liabilities
34,733 
Other current liabilities5,451 
Asset retirement obligation22,156 
Other liabilities28,356 
Total liabilities assumed
90,696 
Net assets acquired$916,159 

The acquisition-date fair values are based on an assessment of the fair value of the assets acquired and liabilities assumed in the Meritage acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the processing plants, gathering system, and related facilities and equipment are based on market and cost approaches.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. ACQUISITIONS AND DIVESTITURES

The following table presents pro forma condensed financial information of the Partnership as if the Meritage acquisition had occurred on January 1, 2022:
Year Ended December 31,
thousands
20232022
Revenues and other$3,239,035 $3,408,767 
Net income (loss) attributable to Western Midstream Partners, LP1,003,204 1,213,106 

The following table presents pro forma condensed financial information of WES Operating (which are included in the Partnership’s pro forma condensed financial information) as if the Meritage acquisition had occurred on January 1, 2022:
Year Ended December 31,
thousands
20232022
Revenues and other$3,239,035 $3,408,767 
Net income (loss) attributable to Western Midstream Operating, LP1,026,800 1,240,623 

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Meritage acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The pro forma adjustments reflect pre-acquisition results of the Meritage acquisition including (i) adjustments of $105.0 million and $221.6 million for the years ended December 31, 2023 and 2022, respectively, to decrease revenues and cost of product to apply the Partnership’s revenue recognition policy to record revenue and cost of product on a net basis within revenues for certain contracts; (ii) adjustments of $5.0 million and $2.1 million for the years ended December 31, 2023 and 2022, respectively, to decrease depreciation and amortization expense based on the acquisition-date fair value of property, plant, and equipment and estimated useful lives; and (iii) adjustments of $1.8 million to decrease interest expense and $20.9 million to increase interest expense for the years ended December 31, 2023 and 2022, respectively, related to the $600.0 million senior note issuance in September 2023 and borrowings on the RCF to finance the Meritage acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The pro forma information reflects recurring adjustments, but does not reflect any cost savings or other synergies anticipated as a result of the Meritage acquisition, nor any future acquisition-related expenses.
The pro forma information in the table above includes $41.4 million of revenues and $24.6 million of operating expenses attributable to the assets acquired as part of the Meritage acquisition that are included in the Partnership’s and WES Operating’s consolidated statements of operations for the year ended December 31, 2023.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. 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.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PARTNERSHIP DISTRIBUTIONS

Partnership distributions. Under its partnership agreement, the Partnership distributes all of its available cash to unitholders of record on the applicable record date within 55 days following each quarter’s end. 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.
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
2021
March 31$0.315 $132,969 May 14, 2021April 30, 2021
June 300.319 134,662 August 13, 2021July 30, 2021
September 300.323 134,862 November 12, 2021November 1, 2021
December 310.327 134,749 February 14, 2022January 31, 2022
2022
March 31$0.500 $206,197 May 13, 2022May 2, 2022
June 300.500 197,744 August 12, 2022August 1, 2022
September 300.500 197,065 November 14, 2022October 31, 2022
December 310.500 196,569 February 13, 2023February 1, 2023
2023
March 31 (1)
$0.856 $336,987 May 15, 2023May 1, 2023
June 300.5625 221,442 August 14, 2023July 31, 2023
September 300.575 223,432 November 13, 2023November 1, 2023
December 310.575 223,438 February 13, 2024February 1, 2024
_________________________________________________________________________________________
(1)Includes the regular quarterly distribution of $0.500 per unit, or $196.8 million, as well as the Enhanced Distribution of $0.356 per unit discussed below.

To facilitate the distribution of available cash, during 2022 the Partnership 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 the Partnership’s business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of total principal debt outstanding less total cash on hand as of the end of such period, as compared to 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 Part II, Item 7 of this Form 10-K. In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to the Partnership’s 2022 performance, which was paid in conjunction with the regular first-quarter 2023 distribution on May 15, 2023.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PARTNERSHIP 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 and/or declared the following cash distributions to its limited partners for the periods presented:
thousands
Quarters Ended
Total Quarterly
Cash Distribution		Distribution
Date
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
2023
March 31 (1)
$342,895 May 2023
June 30226,260 August 2023
September 30229,446 November 2023
December 31229,446 February 2024
_________________________________________________________________________________________
(1)Includes amounts related to the Enhanced Distribution discussed above.

In addition to the distributions above, during the years ended December 31, 2023 and 2022, WES Operating made distributions of $130.1 million and $463.8 million, respectively, to the Partnership and WGRAH. The Partnership used its portion of the distributions to repurchase common units. See Note 5.

116
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2023, Occidental held 185,181,578 common units, representing a 47.7% 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 194,338,405 common units, representing a 50.0% 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.

Partnership equity repurchases. In 2022, the Board authorized the Partnership to buy back up to $1.25 billion of the Partnership’s common units through December 31, 2024 (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, 2023, the Partnership repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. 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, on the open market for an aggregate purchase price of $487.6 million. The units were canceled immediately upon receipt. As of December 31, 2023, the Partnership had an authorized amount of $627.8 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 “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 common units on the open market during the years ended December 31, 2021, for an aggregate purchase price of $167.2 million. 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, 2023, (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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 amounts202320222021
Net income (loss)
Limited partners’ interest in net income (loss)$998,532 $1,189,562 $896,477 
Weighted-average common units outstanding
Basic383,028 394,951 411,309 
Dilutive effect of non-vested phantom units1,380 1,285 713 
Diluted384,408 396,236 412,022 
Excluded due to anti-dilutive effect114 554 589 
Net income (loss) per common unit
Basic$2.61 $3.01 $2.18 
Diluted$2.60 $3.00 $2.18 

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,
thousands202320222021
Revenues and other
Service revenues – fee based$1,773,914 $1,674,959 $1,589,367 
Service revenues – product based16,497 56,907 11,888 
Product sales43,683 63,367 31,103 
Total revenues and other1,834,094 1,795,233 1,632,358 
Equity income, net – related parties (1)
152,959 183,483 204,645 
Operating expenses
Cost of product (2)
(72,903)(25,447)42,805 
Operation and maintenance4,618 5,081 27,805 
General and administrative (3)
284 2,338 15,613 
Total operating expenses(68,001)(18,028)86,223 
Gain (loss) on divestiture and other, net— (1,756)420 
_________________________________________________________________________________________
(1)See Note 7.
(2)Includes related-party natural-gas and NGLs imbalances.
(3)Balances for the years ended December 31, 2022 and 2021, include 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). The balance for the year ended December 31, 2021, also includes amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6).
118
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

Consolidated balance sheets
December 31,
thousands20232022
Assets
Accounts receivable, net$358,141 $313,937 
Other current assets1,260 1,578 
Equity investments (1)
904,535 944,696 
Other assets43,216 29,058 
Total assets1,307,152 1,289,269 
Liabilities
Accounts and imbalance payables38,541 32,150 
Accrued liabilities4,979 11,756 
Other liabilities (2)
335,320 268,399 
Total liabilities378,840 312,305 
_________________________________________________________________________________________
(1)See Note 7.
(2)Includes contract liabilities from contracts with customers. See Note 2.

Consolidated statements of cash flows
Year Ended December 31,
thousands202320222021
Distributions from equity-investment earnings – related parties
$155,169 $186,153 $213,516 
Capital expenditures— (470)(2,000)
Proceeds from the sale of assets to related parties— 200 — 
Contributions to equity investments – related parties(1,153)(9,632)(4,435)
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 41,385 
Distributions to Partnership unitholders (1)
(494,127)(372,468)(272,192)
Distributions to WES Operating unitholders (2)
(22,850)(24,898)(14,984)
Net contributions from (distributions to) related parties— 1,423 8,533 
Unit repurchases from Occidental (3)
(127,500)(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)Represents common units repurchased from Occidental (see Note 5).


119
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
thousands202320222021
General and administrative (1)
$3,554 $5,373 $18,365 
_________________________________________________________________________________________
(1)Includes an intercompany service fee between the Partnership and WES Operating. Balances for the years ended December 31, 2022 and 2021, include 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). The balance for the year ended December 31, 2021, also includes amounts charged by Occidental pursuant to the shared services agreement (see Services Agreement within this Note 6).

Consolidated balance sheets
December 31,
thousands20232022
Other current assets$1,235 $1,487 
Other assets41,405 28,459 
Accounts and imbalance payables (1)
69,472 76,131 
Accrued liabilities4,662 11,439 
_________________________________________________________________________________________
(1)Includes balances related to transactions between the Partnership and WES Operating.

Consolidated statements of cash flows
Year Ended December 31,
thousands202320222021
Distributions to WES Operating unitholders (1)
$(1,142,217)$(1,244,533)$(749,018)
_________________________________________________________________________________________
(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 34%, 35%, and 36% for the years ended December 31, 2023, 2022, and 2021, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 86%, 89%, and 89% for the years ended December 31, 2023, 2022, and 2021, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 78%, 80%, and 87% for the years ended December 31, 2023, 2022, and 2021, respectively.
120
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 allowed 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 is not liable for any obligations under the Brasada gas processing agreement after June 30, 2023. For all periods presented, Mesquite 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 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. Certain surface-use and salt-water disposal agreements between an affiliate of Occidental and certain wholly owned subsidiaries of the Partnership are classified as operating leases (see Related-party commercial agreement below). In addition, the Partnership has entered into operating leases for corporate and shared field offices with Occidental as the 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 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.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for field-related costs, shared field offices, and easements (see Related-party commercial agreement below) supporting the Partnership’s operations at certain 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 Marketing Transition Services Agreement in the section above. Related-party expenses bear no direct relationship to related-party revenues, and third-party expenses bear no direct relationship to third-party revenues.

Services Agreement. Occidental performed certain centralized corporate functions for the Partnership and WES Operating pursuant to the agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP (“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.
121
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

Incentive Plans. General and administrative expense for the years ended December 31, 2022 and 2021, 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 and $10.1 million for the years ended December 31, 2022 and 2021, respectively. These amounts are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital.

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. Also, as a result of the amendments under the CUA, these agreements are 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 through 2038, the remaining term of the agreements.

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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS

The following tables present the financial statement impact of the Partnership’s equity investments:

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.

thousandsBalance at December 31, 2022Equity
income, net		ContributionsDistributions
Distributions
in excess of
cumulative
earnings (1)
Balance at December 31, 2023
White Cliffs$16,095 $2,094 $— $(1,720)$(3,221)$13,248 
Rendezvous16,114 (2,621)— (638)(2,040)10,815 
Mont Belvieu JV91,310 23,476 — (23,128)(3,102)88,556 
TEG15,856 3,504 700 (3,527)(1,348)15,185 
TEP184,687 35,578 — (35,829)(11,877)172,559 
FRP192,716 47,829 — (48,003)(5,991)186,551 
Whitethorn LLC146,595 (6,870)132 6,398 (1,456)144,799 
Saddlehorn104,191 24,003 — (23,545)(2,889)101,760 
Panola19,311 2,507 — (2,638)(464)18,716 
Mi Vida48,862 9,135 — (8,215)(4,358)45,424 
Red Bluff Express108,959 14,324 321 (14,324)(2,358)106,922 
Total$944,696 $152,959 $1,153 $(155,169)$(39,104)$904,535 
_________________________________________________________________________________________
(1)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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS

The investment balance in White Cliffs at December 31, 2023, 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, 2023, includes $20.6 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, 2023, is $32.8 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, 2023, was $17.1 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 November 2022, the Partnership sold its 15.00% interest in Cactus II to two third parties. 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.
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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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
thousands202320222021
Revenues$1,572,120 $1,922,733 $1,808,791 
Operating income619,597 661,779 946,299 
Net income623,593 661,916 945,801 
December 31,
thousands20232022
Current assets$302,675 $293,539 
Property, plant, and equipment, net4,114,540 4,278,398 
Other assets50,693 52,163 
Total assets$4,467,908 $4,624,100 
Current liabilities$130,028 $123,897 
Non-current liabilities17,920 17,660 
Equity4,319,960 4,482,543 
Total liabilities and equity$4,467,908 $4,624,100 

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, 2023 and 2022, 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,
thousands202320222021
Current state income tax expense (benefit)$3,341 $2,188 $(37)
Deferred state income tax expense (benefit)1,044 1,999 (9,770)
Total income tax expense (benefit)$4,385 $4,187 $(9,807)

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
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 percentages202320222021
Income (loss) before income taxes$1,052,392$1,255,643$934,192
Statutory tax rate— %— %— %
Tax computed at statutory rate$— $— $— 
Adjustments resulting from:
Texas margin tax expense (benefit) (1)
4,3854,187(9,807)
Income tax expense (benefit)$4,385$4,187$(9,807)
Effective tax rate— %— %(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,
thousands20232022
Depreciable property$(15,467)$(14,114)
Other intangible assets(588)(603)
Other587 293 
Net long-term deferred income tax liabilities$(15,468)$(14,424)

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. PROPERTY, PLANT, AND EQUIPMENT

A summary of the historical cost of property, plant, and equipment is as follows:
December 31,
thousandsEstimated Useful Life20232022
LandN/A$12,504 $10,982 
Gathering systems – pipelines30 years5,890,607 5,519,592 
Gathering systems – compressors15 years2,553,602 2,266,410 
Processing complexes and treating facilities25 years3,745,332 3,419,201 
Transportation pipeline and equipment
3 to 48 years
259,314 174,241 
Produced-water disposal systems
20 years1,098,616 932,627 
Assets under constructionN/A479,368 263,353 
Other
3 to 40 years
906,088 779,187 
Total property, plant, and equipment14,945,431 13,365,593 
Less accumulated depreciation5,290,415 4,823,993 
Net property, plant, and equipment$9,655,016 $8,541,600 

“Assets under construction” represents property that is not yet placed into productive service as of the respective balance sheet date and is excluded from capitalized costs being depreciated.

Long-lived asset impairments. During the year ended December 31, 2023, the Partnership recognized a long-lived asset impairment of $52.1 million for assets located in the Rockies due to a reduction in estimated future cash flows resulting from a contract termination notice received in the first quarter of 2023. This asset was impaired to its estimated fair value of $22.8 million. The fair value was 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.
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.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. The Partnership’s goodwill had been allocated to two reporting units: (i) gathering and processing and (ii) transportation. As of December 31, 2023, the carrying value of goodwill for the gathering and processing reporting unit was zero and goodwill allocated to the transportation reporting unit was $4.8 million. The Partnership’s annual goodwill impairment assessment indicated no impairment for the year ended December 31, 2023.

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 the 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 20232022
Gross carrying value$979,863 $979,863 
Accumulated amortization(298,455)(266,788)
Other intangible assets$681,408 $713,075 

Amortization expense for intangible assets was $31.7 million for each of the years ended December 31, 2023, 2022, and 2021. Intangible asset amortization to be recorded in each of the next five years is estimated to be $31.7 million per year.

128
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. SELECTED COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2023202220232022
Trade receivables, net$665,892 $548,859 $665,892 $548,859 
Other receivables, net745 5,404 723 5,404 
Total accounts receivable, net$666,637 $554,263 $666,615 $554,263 

A summary of other current assets is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2023202220232022
NGLs inventory$2,557 $3,797 $2,557 $3,797 
Imbalance receivables5,056 32,658 5,056 32,658 
Prepaid insurance21,065 13,262 18,571 11,139 
Contract assets9,595 3,381 9,595 3,381 
Other14,713 6,408 14,689 6,316 
Total other current assets$52,986 $59,506 $50,468 $57,291 

A summary of accrued liabilities is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2023202220232022
Accrued interest expense$124,937 $110,486 $124,937 $110,486 
Short-term asset retirement obligations
7,606 10,493 7,606 10,493 
Short-term remediation and reclamation obligations
5,490 5,383 5,490 5,383 
Income taxes payable2,908 2,428 2,908 2,428 
Contract liabilities16,866 20,903 16,866 20,903 
Accrued payroll and benefits55,237 44,855 2,243 — 
Other49,528 60,092 43,411 47,596 
Total accrued liabilities$262,572 $254,640 $203,461 $197,289 
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:
 Year Ended December 31,
thousands20232022
Carrying amount of asset retirement obligations at beginning of year$300,514 $308,209 
Liabilities incurred34,929 10,513 
Liabilities settled(11,273)(10,115)
Accretion expense15,040 14,474 
Revisions in estimated liabilities27,581 (22,567)
Carrying amount of asset retirement obligations at end of year$366,791 $300,514 

Liabilities incurred for the year ended December 31, 2023, primarily related to the acquisition of Meritage and expansion activity in West Texas. Revisions in estimated liabilities for the year ended December 31, 2023, primarily related to an increase in expected settlement costs across all areas of operations.
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 Hilight system.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
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, 2023December 31, 2022
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 
Commercial paper613,885 610,312 610,312 — — — 
Finance lease liabilities7,436 7,436 7,436 2,659 2,659 2,659 
Total short-term debt
$621,321 $617,748 $617,748 $215,797 $215,780 $217,482 
Long-term debt
3.100% Senior Notes due 2025
$666,481 $665,145 $650,765 $730,706 $727,953 $692,491 
3.950% Senior Notes due 2025
349,163 347,938 341,415 399,163 396,825 379,107 
4.650% Senior Notes due 2026
467,204 465,705 459,617 474,242 472,161 452,201 
4.500% Senior Notes due 2028
357,094 354,665 346,121 400,000 396,698 368,346 
4.750% Senior Notes due 2028
382,888 380,747 374,767 400,000 397,340 368,141 
6.350% Senior Notes due 2029
600,000 593,069 626,994 — — — 
4.050% Senior Notes due 2030
1,104,593 1,097,609 1,036,097 1,200,000 1,191,345 1,053,038 
6.150% Senior Notes due 2033
750,000 741,125 780,203 — — — 
5.450% Senior Notes due 2044
600,000 594,031 545,154 600,000 593,878 503,742 
5.300% Senior Notes due 2048
700,000 687,735 614,082 700,000 687,494 580,570 
5.500% Senior Notes due 2048
350,000 342,913 312,365 350,000 342,783 291,194 
5.250% Senior Notes due 2050
1,000,000 984,206 895,440 1,000,000 983,945 829,804 
RCF— — — 375,000 375,000 375,000 
Finance lease liabilities28,668 28,668 28,668 4,160 4,160 4,160 
Total long-term debt
$7,356,091 $7,283,556 $7,011,688 $6,633,271 $6,569,582 $5,897,794 
_________________________________________________________________________________________
(1)Fair value is measured using the market approach and Level-2 fair value inputs.
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

Debt activity. The following table summarizes debt activity for the periods presented:
thousandsCarrying Value
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 
RCF borrowings1,120,000 
Commercial paper borrowings (1)
610,312 
Repayments of RCF borrowings(1,495,000)
Issuance of 6.350% Senior Notes due 2029
600,000 
Issuance of 6.150% Senior Notes due 2033
750,000 
Repayment of Floating-Rate Senior Notes due 2023(213,138)
Repayment of 3.100% Senior Notes due 2025
(64,225)
Repayment of 3.950% Senior Notes due 2025
(50,000)
Repayment of 4.650% Senior Notes due 2026
(7,038)
Repayment of 4.500% Senior Notes due 2028
(42,906)
Repayment of 4.750% Senior Notes due 2028
(17,112)
Repayment of 4.050% Senior Notes due 2030
(95,407)
Finance lease liabilities29,285 
Other(8,829)
Balance at December 31, 2023$7,901,304 
________________________________________________________________________________________
(1)Net of repayments related to commercial paper notes with maturities of 90 days or less.

WES Operating Senior Notes. WES Operating issued the Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and the Floating-Rate Senior Notes due 2023 in January 2020. 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 3.290%, 4.169%, and 5.363%, respectively, at December 31, 2023, and were 3.790%, 4.671%, and 5.869%, respectively, 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.
During the third quarter of 2023, WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Interest is payable semi-annually on January 15th and July 15th of each year, with the initial interest payment being due on January 15, 2024. Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition (see Note 3), to pay related costs and expenses, and for general partnership purposes.
During the second quarter of 2023, WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Interest is payable semi-annually on April 1st and October 1st of each year, with the initial interest payment being due on October 1, 2023. Net proceeds from the offering were used to repay borrowings under the RCF and for general partnership purposes.
During the year ended December 31, 2023, WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases and redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand (see Debt activity above). For the year ended December 31, 2023, a gain of $15.4 million was recognized for the early retirement of portions of these notes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

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, 2023, WES Operating was in compliance with all covenants under the relevant governing indentures.

Revolving credit facility. In April 2023, WES Operating (i) repaid all then-outstanding borrowings under its RCF with proceeds from the 6.150% Senior Notes due 2033 offering, and (ii) entered into an amendment to its RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date.
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.
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, as defined in the RCF agreement, 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.
As of December 31, 2023, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $1.4 billion in effective borrowing capacity, after taking into account the $613.9 million of outstanding commercial paper borrowings (see below), for which we maintain availability under the RCF as support for WES Operating’s commercial paper program. As of December 31, 2023 and 2022, the interest rate on any outstanding RCF borrowings was 6.65% and 5.92%, respectively. The facility-fee rate was 0.20% and 0.25% at December 31, 2023 and 2022, respectively. As of December 31, 2023, WES Operating was in compliance with all covenants under the RCF.

Commercial paper program. In November 2023, WES operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion. WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings. The maturities of the notes may vary, but may not exceed 397 days. As of December 31, 2023, there were $613.9 million aggregate principal amount of short-term notes outstanding under the commercial paper program at a weighted-average interest rate of 6.23% and weighted-average maturity of 34 days.

Interest expense. The following table summarizes the amounts included in interest expense:
Year Ended December 31,
thousands202320222021
Long-term and short-term debt
$(348,393)$(326,949)$(366,570)
Finance lease liabilities(1,083)(414)(861)
Commitment fees and amortization of debt-related costs(12,395)(12,212)(12,705)
Capitalized interest 13,643 5,636 3,624 
Interest expense$(348,228)$(333,939)$(376,512)
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. 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 has also entered into finance leases with third parties for equipment, vehicles, and an NGL pipeline in Wyoming.
The following table summarizes information related to the Partnership’s leases:
December 31,
20232022
thousands except lease term and discount rateOperating LeasesFinance LeasesOperating LeasesFinance Leases
Assets
Other assets$84,279 $— $67,087 $— 
Net property, plant, and equipment— 36,958 — 7,402 
Total lease assets (1)
$84,279 $36,958 $67,087 $7,402 
Liabilities
Accrued liabilities$11,259 $— $10,342 $— 
Short-term debt— 7,436 — 2,659 
Other liabilities48,459 — 33,318 — 
Long-term debt— 28,668 — 4,160 
Total lease liabilities (1)
$59,718 $36,104 $43,660 $6,819 
Weighted-average remaining lease term (years)9686
Weighted-average discount rate (%)4.6 7.1 4.5 8.2 
________________________________________________________________________________________
(1)Includes additions to ROU assets and lease liabilities of $33.1 million and $8.3 million related to operating leases for the years ended December 31, 2023 and 2022, respectively. Includes additions to ROU assets and lease liabilities of $32.6 million and $7.1 million related to finance leases for the years ended December 31, 2023 and 2022, respectively.

The following table summarizes the Partnership’s lease cost:
Year Ended December 31,
thousands202320222021
Operating lease cost$15,457 $14,767 $10,753 
Short-term lease cost48,343 38,875 37,616 
Variable lease cost3,930 5,611 2,628 
Sublease income(311)(414)(414)
Finance lease cost
Amortization of ROU assets3,487 5,377 7,151 
Interest on lease liabilities1,083 414 861 
Total lease cost$71,989 $64,630 $58,595 
134
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
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,
202320222021
thousandsOperating LeasesFinance LeasesOperating LeasesFinance LeasesOperating LeasesFinance Leases
Operating cash flows$14,217 $1,083 $13,616 $229 $5,805 $861 
Financing cash flows— 3,076 — 4,318 — 6,513 

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities at December 31, 2023:
 
Operating LeasesFinance Leases
2024$11,593 $7,670 
20259,542 10,527 
20268,267 9,274 
20277,849 5,814 
20287,993 5,659 
Thereafter34,020 3,795 
Total lease payments79,264 42,739 
Less portion representing imputed interest19,546 6,635 
Total lease liabilities$59,718 $36,104 

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 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. The agreement and underlying contracts included (i) fixed consideration measured as the minimum-volume commitment for both gathering and treating, and (ii) variable consideration, which consisted of all volumes above the minimum-volume commitment. For the year ended December 31, 2021, the Partnership recognized fixed-lease revenue of $175.8 million and variable-lease revenue of $3.5 million 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).

135
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
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 1,226,875 and 9,479,648 units, respectively, remained available for future issuance as of December 31, 2023. 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 certain members of the leadership team of the Partnership 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 paid in-kind distributions in the form of Partnership common units. During the years ended December 31, 2023, 2022, and 2021, the Partnership issued 3,253, 13,754, and 21,681 common units, respectively, as in-kind distributions under such Awards. Prior to vesting, the Time-Based Awards granted after 2020 pay distribution equivalents in cash ratably. The TUR and ROA Awards granted after 2020 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 $23.4 million, $21.7 million, and $8.5 million for the years ended December 31, 2023, 2022, and 2021, respectively, based on the market price at the vesting date. Compensation expense for the WES LTIPs was $32.0 million, $25.5 million, and $17.6 million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, the Partnership had $41.0 million of estimated unrecognized compensation expense attributable to the WES LTIPs that will be recognized over a weighted-average period of 0.9 years.

136
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. EQUITY-BASED COMPENSATION

The following table summarizes time-vested award activity under the WES LTIPs:
202320222021
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$21.33 1,689,030 $16.97 1,775,672 $15.69 1,307,606 
Granted28.19 1,140,789 26.11 866,900 17.86 1,041,635 
Vested19.66 (910,062)16.84 (793,367)14.82 (497,648)
Forfeited25.73 (183,055)21.12 (160,175)16.83 (75,921)
Non-vested units at end of year26.24 1,736,702 21.33 1,689,030 16.97 1,775,672 

The following table summarizes TUR Awards activity under the WES LTIPs:
202320222021
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$24.62 388,817 $21.17 325,217 $17.79 108,481 
Granted40.44 231,395 37.80 94,173 22.77 237,720 
Vested17.79 (155,052)— — — — 
Forfeited40.22 (1,631)28.54 (30,573)21.78 (20,984)
Non-vested units at end of year32.22 463,529 24.62 388,817 21.17 325,217 

The following table summarizes ROA Awards activity under the WES LTIPs:
202320222021
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$18.12 388,817 $16.01 325,217 $16.27 108,481 
Granted28.48 245,143 25.95 94,173 15.88 237,720 
Vested16.27 (168,800)— — — — 
Forfeited28.38 (1,631)19.74 (30,573)15.96 (20,984)
Non-vested units at end of year22.51 463,529 18.12 388,817 16.01 325,217 

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
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, 2023 and 2022, the consolidated balance sheets included $7.3 million and $7.4 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. See Note 11.
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.

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 expansion, construction, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system.
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. SUBSEQUENT EVENTS

On February 21, 2024, the Partnership announced its entry into definitive agreements for the divestment of the following assets: (i) the 33.75% interest in the Marcellus Interest systems, (ii) the 15.00% interest in Panola Pipeline Company, LLC (“Panola”), (iii) the 25.00% interest in Enterprise EF78 LLC (the “Mont Belvieu JV”), (iv) the 20.00% interest in Whitethorn Pipeline Company LLC (“Whitethorn LLC”), and (v) the 20.00% interest in Saddlehorn Pipeline Company LLC (“Saddlehorn”). As disclosed in Note 1—Summary of Significant Accounting Policies and Basis of Presentation within this Form 10-K, the interest in the Marcellus Interest systems is proportionately consolidated, while the interests in Panola, the Mont Belvieu JV, Whitethorn LLC, and Saddlehorn are accounted for under the equity method of accounting. The sale of the interests in the Mont Belvieu JV and Whitethorn LLC on February 16, 2024, also resolved outstanding legal proceedings associated with those assets. The sale of the Marcellus Interest systems, Panola, and Saddlehorn are expected to close in the first or second quarters of 2024, subject to customary closing conditions. The divestments are expected to result in combined proceeds of $790.0 million for an estimated aggregate net gain on sale of approximately $300.0 million. The proceeds payable under each transaction will be subject to customary adjustments calculated at closing.

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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, 2023.

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. On April 1, 2023, WES and WES Operating implemented a new Enterprise Resource Planning (“ERP”) system. As a result of this implementation, certain internal controls over financial reporting have been automated, modified, or implemented to address the new environment associated with the implementation of this type of system. While WES and WES Operating believe that this system will strengthen the internal control system, there are inherent risks in implementing any new system and WES and WES Operating will continue to evaluate these control changes as part of their assessments of internal control over financial reporting. Other than the ERP implementation, there have been no changes in WES’s or WES Operating’s internal control over financial reporting during the quarter ended December 31, 2023, 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

Insider Trading Arrangements

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three months ended December 31, 2023, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading arrangement (as defined in Item 408(a)(1)(i) of Regulation S-K) or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

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 14, 2024.
NameAgePosition with Western Midstream Holdings, LLC
Peter J. Bennett56Chairperson of the Board
Michael P. Ure47President, Chief Executive Officer, and Director
Kristen S. Shults39Senior Vice President and Chief Financial Officer
Robert W. Bourne68Senior Vice President and Chief Commercial Officer
Christopher B. Dial47Senior Vice President, General Counsel and Secretary
Michael S. Forsyth58Senior Vice President, North Operations
Catherine A. Green50Senior Vice President and Chief Accounting Officer
Daniel P. Holderman44Senior Vice President, South Operations
Alejandro O. Nebreda
49
Senior Vice President, Business Services
Oscar K. Brown53Director
Nicole E. Clark 54Director
Frederick A. Forthuber 60Director
Kenneth F. Owen 50Director
David J. Schulte 62Director
Lisa A. Stewart 66Director

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. Since June 2023, Mr. Bennett has served as the Chairman of the Board of Directors of Net Power Inc., an NYSE listed company focused on renewable energy.
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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 13 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 33 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 the general partner of Western Midstream Partners, LP since December 2019. Prior to joining Western Midstream, from January 2018 to September 2019, Mr. Dial served as Senior Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer of the general partner of American Midstream Partners, LP. Mr. Dial also previously spent over 10 years in a number of in-house legal roles, most recently as General Counsel of Susser Holdings II, LP, Associate General Counsel of Susser Holdings Corporation, and Associate General Counsel and Corporate Secretary of Sunoco LP. Mr. Dial began his career as an Associate Attorney in the corporate section of the Houston office of Andrews Kurth, LLP, working on corporate, capital markets, governance, and other transactional matters primarily in the energy industry.
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 31 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 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.
Alejandro O. Nebreda
Houston, Texas
Officer since:
March 2021
Biography/Qualifications
 
Mr. Nebreda has served as Senior Vice President, Business Services of our general partner since March 2021, and as Vice President, Business Services of our general partner since August 2020. Prior to joining WES, Mr. Nebreda served as Chief Operating Officer of CIG Logistics from 2018 to July 2020. Prior to CIG Logistics, Mr. Nebreda served as Vice President of Integrated Planning of Occidental Oil and Gas Corporation, a subsidiary of Occidental, from 2006 to 2018. Mr. Nebreda has over 25 years of domestic and international experience within the oil and gas, retail, telecommunications, manufacturing, and transportation industries.
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, Corporate Secretary, Chief Compliance Officer, and Deputy General Counsel 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.
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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 38 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. Since June 2023, Mr. Forthhuber has served on the Board of Directors of Net Power, Inc., an NYSE listed company focused on renewable energy.
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 and Chief Executive Officer 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 42 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.


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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.

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 understands 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 four meetings during 2023.
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 six meetings during 2023.

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Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our Board, 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 2023. 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 2023 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.

2023 Named Executive Officers

Ure.jpg
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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
Alejandro O. Nebreda
Senior Vice President, Business Services

Executive Summary

Our strategic objective is to create 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 2023, our Board took the following key actions related to executive compensation:

•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;

•Approved a clawback policy (“Clawback Policy”) requiring WES to recoup certain incentive-based compensation from executive officers in the event WES becomes required to issue a financial restatement;

•Reviewed our annual cash incentive program design and metrics and made changes to our operational and sustainability components to better align the program with the Partnership’s overall business strategy;

•Approved a discretionary bonus pool for the Partnership’s non-CEO Section 16 officers, which includes the NEOs other than Mr. Ure (the “S16 Discretionary Bonus Pool”); and

•Broadened the peer groups used to benchmark compensation for our executive officers and determine the performance of our total unitholder (“TUR”) return incentive awards.

These actions were taken to further align our executive compensation program with WES’s overall strategy, ensure our compliance with applicable regulations, provide for the attraction and retention of executive talent, and align our executive officers’ interest with those of our long-term unitholders.

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2023 Business and Performance Highlights

2023 was a year of remarkable achievements for WES, as it continued to grow its core businesses and improve its operations. In particular, during the 2023 fiscal year WES:

•Achieved record annual natural-gas throughput of 4.4 Bcf/d, representing a 5-percent year-over-year increase.

•Gathered record annual produced-water throughput of 1,009 MBbls/d, representing a 21-percent year-over-year increase.

•Achieved year-over-year throughput growth across all products in the Delaware Basin of 11-percent, 8-percent, and 21-percent, for natural gas, crude oil and NGLs, and produced water, respectively.

•Sanctioned the 250 MMcf/d North Loving processing plant in May 2023, and materially progressed construction of the 300 MMcf/d Mentone III processing train.

•Announced and closed the Meritage acquisition, giving WES the largest gathering and processing footprint in the Powder River Basin.

•Executed on our capital return framework by returning $978 million in distributions, inclusive of two Base Distribution increases and the payment of our first Enhanced Distribution, and $135 million in unit repurchases.

•Obtained full investment-grade ratings in May 2023 and raised $1.350 billion through two bond offerings to partially fund the Meritage acquisition, refinance existing borrowings, and enhance the partnership’s overall liquidity.

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 judgment and discretion as deemed appropriate.

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. 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 design a total compensation package for its executive officers, including the NEOs, that generally provides for, approximately (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 have grant values within the third-quartile of market.

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The Compensation Committee utilizes this compensation framework along with the Partnership’s performance, individual performance, and general market conditions to determine the final compensation awards for the NEOs. However, the compensation we pay to our NEOs may ultimately fall above or below the approximate ranges discussed above. This may occur for a number of reasons. First, the data provided by our compensation consultant for benchmarking is inherently dated because it is reported by our peers on a trailing basis. Second, the data provided may not correspond exactly to the positions and individual responsibilities of our NEOs. Third, our peers use differing compensation practices than we do to varying degrees, and this may require us to make interpretative assumptions and adjustments when comparing data for benchmarking purposes. Fourth, and finally, the Compensation Committee considers each NEO’s individual professional background and performance characteristics in addition to general benchmarking when making final compensation determinations.
The Board and the Compensation Committee believe the design of our executive compensation program, and the Compensation Committee’s decisions and outcomes in 2023, support our compensation philosophy and objectives by ensuring:

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

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

•Compensation aligns with unitholder interests;

•Performance-based compensation balances short-term and long-term results; and

•Total compensation opportunities are 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, their annual base salaries, annual bonus or incentive opportunities, equity-based opportunities (including time-vested and performance-based phantom units), any supplemental benefits, and any employment, severance, or change-in-control agreements, and making 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 our compensation process.

What We Do

ü
•Align executive officer pay with performance by structuring more than 82% 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 a clawback policy governing our incentive-based compensation
•Provide for "double trigger" severance benefits in the event of a change of control and qualifying termination
What We
Don’t Do
X
•Provide excessive perquisites or personal benefits to our executive officers
•Allow short-selling or hedging of company securities
•Provide excise tax gross-ups
•Offer guaranteed bonuses
•Have automatic base salary increases

Role of the Compensation Consultant. For the 2023 calendar year, the Compensation Committee retained Zayla Partners as its independent compensation consultant to provide advice on various executive compensation matters. In 2023, Zayla Partners provided guidance on our benchmarking peer group, TUR performance peer group, pay levels, pay mix, and overall executive compensation program design. The independent executive compensation consultant reports directly to the Compensation Committee and the Board and provides no other material services to us.

Benchmarking Peers. With assistance from Zayla Partners, the Compensation Committee evaluated several factors when determining an appropriate peer group of companies to use for 2023 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 corporation)), and companies that are in competition for the same senior executive talent. After conducting an annual review, the Compensation Committee approved broadening the Partnership’s peer group used to evaluate 2023 compensation decisions. The Partnership’s peer group used for conducting the 2023 executive benchmarking assessment is listed below:

Antero Midstream Corporation
Magellan Midstream Partners, L.P. (3)
Cheniere Energy, Inc.NiSource Inc.
Crestwood Equity Partners LP (1)
NuStar Energy, L.P.
DCP Midstream, LP (2)
ONEOK, Inc.
DT Midstream, Inc.Plains All American Pipeline, L.P.
Energy Transfer LPTarga Resources Corp.
EnLink Midstream, LLCTellurian Inc.
Equitrans Midstream CorporationThe Williams Companies, Inc.
Genesis Energy, L.P.
_________________________________________________________________________________________
(1)Crestwood Equity Partners LP was acquired by Energy Transfer LP as of November 3, 2023.
(2)DCP Midstream, LP was acquired by Phillips 66 as of June 15, 2023.
(3)Magellan Midstream Partners, L.P. was acquired by ONEOK, Inc. as of September 25, 2023.
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Benchmarking Data. To assist in reviewing the design and structure of our executive compensation program, Zayla Partners provided the Compensation Committee 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 peer company. In establishing competitive compensation benchmark levels, Zayla Partners blended the publicly disclosed peer group data with published third-party survey data. The published survey data was gathered based on industry and company size (revenues from $1-6 billion) and included the following surveys: Willis Towers Watson Industry Executive Survey, Mercer Total Compensation Survey for the Energy Sector and the Economic Research Institute Executive Compensation Assessor Data for Pipeline and Midstream Services. When reviewing benchmarking data, the Compensation Committee reviewed 25th, 50th, and 75th percentile data in connection with the general structuring of the officers’ compensation packages; however, in making specific officer compensation decisions, the Board has taken into account other considerations as noted above and below.

Role of Executive Officers in Setting Executive Compensation. The Board, after reviewing the information provided by Zayla Partners for 2023 and considering other factors described below, determines, with input from Zayla Partners, 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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2023 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, a majority of our NEO’s targeted annual direct compensation is at-risk, including 89% for our CEO and 82%, on average, for our other NEOs. Further, 75% of our CEO’s targeted annual direct compensation and 68%, 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

MixOfPay2023.jpg

The charts above are based on the following compensation elements, as discussed under Analysis of 2023 Compensation Actions: base salaries approved in 2023; 2023 target bonus opportunities; and the target value of the 2023 annual long-term incentive awards. The charts do not include allocations to the non-CEO NEOs under the S16 Discretionary Bonus Pool, if any.

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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 incentives 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/A
Provides 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 Price
Time-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”)

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 Units reward unit price performance relative to our industry performance peer group, align the interests of our NEOs with that of our unitholders, and provide a retentive value.
Annual Cash Incentives
Company Performance Cash Bonus
Adjusted EBITDA
Free Cash Flow
System Operability
TRIR
Volunteer Participation
Greenhouse Gas
Based on the achievement of WES’s performance goals, which are aligned with key financial, operational, and sustainability metrics, the annual cash bonus provides incentives for the NEOs to focus and excel in areas aligned with WES’s short-term business objectives.
Discretionary Cash Bonus (Non-CEO NEOs)
Recommendation by the CEO and Compensation Committee to the Board
Based on the achievement of each non-CEO NEO’s individual and team contribution to WES’s performance.

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Analysis of 2023 Compensation Actions

The following is a discussion of the specific actions taken by the Board in 2023 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.

Name
Salary Approved in 2022 ($)
Salary Approved in 2023 ($)
% Change
Mr. Ure775,000 900,000 16.1 %
Ms. Shults
400,000 500,000 25.0 %
Mr. Dial425,000 500,000 17.6 %
Mr. Bourne425,000 500,000 17.6 %
Mr. Nebreda (1)
— 500,000 — %
________________________________________________________________________________________
(1)Mr. Nebreda was not an NEO for the year 2022. Additionally, Mr. Nebreda was not a Section 16 officer when the Board approved compensation actions for the year 2023 in respect of the other NEOs. As a result, Mr. Ure approved the Partnership’s compensation actions in respect of Mr. Nebreda.

In accordance with our compensation philosophy, the Board approved an increase to each NEO’s salary to better align it with the median of the peer benchmark data for their respective positions. Additionally, the salary increases for the non-CEO NEOs were based on internal compensation alignment considerations. The approved salary increases positioned each NEO’s base salary slightly above or below 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 2023 to the general 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 75% of targeted annual direct compensation for our CEO and an average of 68% for our other NEOs.

Time-Based Units. These units, reflecting 50% of the overall 2023 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 and, provides a forfeitable ownership stake to encourage executive retention.

Return on Asset Performance Units (“ROA Units”). The Board established ROA as a performance criterion for 25% of the 2023 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 Unitholder Return Performance Units (“TUR Units”). The Board established relative TUR as a performance criterion for 25% of the 2023 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

For the 2023 TUR awards, Zayla Partners reviewed the industry peer group and recommended broadening it to decrease the effect of individual Impacted Peers (defined below) over the performance period and increase the quality of the data sample provided. The industry peer group for our 2023 TUR awards is listed below. Companies that were added to the peer group for the 2023 TUR awards are marked with an asterisk.

Antero Midstream Corporation
Kinetik Holdings Inc.*
Crestwood Equity Partners LP (1)
Magellan Midstream Partners, L.P. (2)
Energy Transfer LP*
MPLX LP*
EnLink Midstream LLC
ONEOK, Inc.*
Enterprise Products Partners L.P.*
Plains All American Pipeline, L.P.
Equitrans Midstream CorporationTarga Resources Corp.
Genesis Energy LP*The Williams Companies*
_________________________________________________________________________________________
(1)Crestwood Equity Partners LP was acquired by Energy Transfer LP as of November 3, 2023.
(2)Magellan Midstream Partners, L.P. was acquired by ONEOK, Inc. as of September 25, 2023.
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For the 2023 TUR awards, if during the performance period, a peer company files for bankruptcy or fails to meet the listing requirements of the relevant securities exchange, then the Partnership will drop such company to the bottom of the relative TUR percentile ranking. If during the performance period, a peer company is acquired, ceases to exist, ceases to be publicly traded, spins off 25% or more of its assets, or sells all or substantially all of its assets (as applicable, an “Impacted Peer”), then the Compensation Committee may, in its discretion, (i) drop such company out of the peer group and recalculate the results, (ii) applying conventions the Compensation Committee deems appropriate under the circumstances, calculate such company’s ranking position at the time of such event and “freeze” its relative TUR percentile ranking, or (iii) drop such company to the bottom of the relative TUR ranking. The Board’s determination in this regard may be made at any point prior to certifying the performance results of the 2023 TUR awards. This approach grants the Compensation Committee the discretion to address unusual situations affecting our peer companies and ensures that the 2023 TUR awards remain aligned with the Partnership’s compensation philosophy and objectives.
In consultation with Zayla Partners, the Board approved a new payout scale for the 2023 TUR awards that strengthens our link to performance by rewarding top quartile performance with a maximum payout of 200% of target and providing for a zero payout for bottom quartile performance. 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. For the 2023 TUR awards, the following table reflects the payout scale used to determine the number of TUR Units earned. In the event performance falls between a whole percentile figure listed in the table below, the payout will be interpolated linearly.

WES TUR Payout Schedule
3 Year TUR Performance
≥ 25th≥ 50th Percentile≥ 75th Percentile
Payout Percentage of Target
50%100%200%

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 paid prior to the settlement of such TUR Units are accrued and paid in cash at the end of the performance period based on the actual performance of the underlying award.

Equity Awards Granted in 2023. In 2023, the Board approved the below annual long-term incentive awards. These awards are included in the Grants of Plan-Based Awards Table. In determining the annual equity awards, and in accordance with our compensation philosophy, the Board took into consideration our peer benchmarking data, internal pay equity, retention concerns, and current NEO unit ownership levels. The target value of the 2023 annual equity awards granted to the NEOs reflect an increase of approximately 72%, on average, compared to their prior year target value of annual awards. The target long-term incentive award increases position each of the NEO awards between the 50th and 75th percentiles of the benchmark data.

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. Ure6,000,000 105,263 3,000,000 52,632 1,500,000 52,632 1,500,000 
Ms. Shults
1,850,000 32,456 925,000 16,228 462,500 16,228 462,500 
Mr. Dial1,850,000 32,456 925,000 16,228 462,500 16,228 462,500 
Mr. Bourne1,850,000 32,456 925,000 16,228 462,500 16,228 462,500 
Mr. Nebreda
1,850,000 32,593 925,000 16,297 462,500 16,297 462,500 
_________________________________________________________________________________________
(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.


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Performance Unit Awards — Results for the Performance Period Ended December 31, 2023. In February 2024, the Compensation Committee recommended for certification, and the Board certified, the performance results for the 2021 annual TUR Unit and ROA Unit awards. These awards had a three-year performance period that began on January 1, 2021, and ended December 31, 2023. Under the 2021 TUR Unit awards, WES ranked 3rd in TUR relative to the established peer group, which resulted in a payout of 150%. Under the 2021 ROA Unit awards, WES achieved a three-year average ROA of 17.9%, which resulted in a payout of 173.3%. 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 2021 annual TUR Unit and ROA Unit awards.

ROA UnitsTUR Units
Paid at 173.3% of Target
Paid at 150% of Target
NameNumber of Units - TargetNumber of Units - EarnedNumber of Units - TargetNumber of Units - Earned
Mr. Ure110,201 190,979 110,201 165,302 
Ms. Shults
— — — — 
Mr. Dial26,764 46,383 26,764 40,146 
Mr. Bourne22,040 38,196 22,040 33,060 
Mr. Nebreda
— — — — 

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 2023, individual bonus targets were approved by the Board for each of our NEOs as noted in the table below. The target bonuses as a percent of salary did not change from the 2022 targets.

2023 Target Bonus
Name$% of Salary
Mr. Ure1,125,000125%
Ms. Shults
400,000
80%
Mr. Dial400,00080%
Mr. Bourne400,00080%
Mr. Nebreda
400,00080%

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 operability, and obtaining new business over time, while achieving costs efficiencies and optimizing our financial profile.
The overall design and performance metrics under the 2023 WCB Program are generally the same as the 2022 WCB Program, but with changes to its operational and sustainability components. With respect to its operational component, the Board approved replacing its “System Availability” metric with a “System Operability” metric. The method for calculating System Operability is discussed in the footnotes to the table below. In doing so, the Board determined that a metric based on System Operability better aligned with the Partnership’s business strategy of minimizing system downtime and continually improving customer service.
With respect to its sustainability component, the Board approved changing the 2022 WCB Program’s quantitative methane reduction metric to a qualitative metric regarding the implementation of certain initiatives related to Greenhouse Gas (“GHG”) emissions. In doing so, the Board determined that a qualitative metric aligned more closely with the Partnership’s sustainability goals by giving management the discretion to pursue projects providing holistic outcomes, rather than those tied to a specific metric. The continued inclusion of environmental and other sustainability metrics in the 2023 WCB Program supports our foundational pillar of sustainable operations through our commitment to the safety of our people, minimizing our emissions footprint, and improving our communities.

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The table below reflects the Partnership’s 2023 performance metrics, performance targets and performance under these metrics.
Performance MetricRelative Weighting Factor
WCB Program
Performance
Targets (7)
WCB Program Performance
Results (8)
Actual Payout %
Financial
Adjusted EBITDA (1)
30%
$2,032MM
$2,048.235%
Free Cash Flow (2)
30%$956MM$1,043.060%
Operational
System Operability (3)
20%98%98.2%23%
Sustainability
TRIR (4)
10%0.430.4211%
Employee Volunteer Participation (5)
4%50% Participation75.0%8%
Greenhouse Gas (6)
6%Qualitative
Exceeded
12%
100%149%
_________________________________________________________________________________________
(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).
(3)System Operability is a measure of the “real” operability experienced by WES’s customers related to its gas systems, oil systems, and water-disposal wells. It considers the ratio of actual throughput each day to the theoretical maximum throughput available to capture by the applicable system. Loss of throughput due to volumes above firm targets and off-spec product do not count against operability.
(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 GHG emissions reduction plan, including various internal initiatives to forecast GHG emissions and identify actionable emissions-reduction projects.
(7)The performance targets in the above table reflect the targets used by the Board in determining bonus payouts under the WCB Program, as discussed further below.
(8)Adjusted EBITDA and Free Cash Flow targets and results include the Board’s discretion to include the impact of the Meritage acquisition. See Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K.

2023 WCB Program Performance Assessment. In assessing the Partnership’s performance under the WCB Program, the Board considered our performance against the targets noted in the above table. These performance targets were approved by the Board in February 2023, with exception to the Adjusted EBITDA and Free Cash Flow measures. For Adjusted EBITDA and Free Cash Flow, the original targets approved were $2,132.0 million and $1,181.0 million, respectively. In assessing WES’s performance under the WCB Program, the Board exercised its discretion and determined it was more appropriate to measure WES’s performance against the midpoint of the revised guidance the Partnership issued following the end of the second quarter 2023. These revised targets reflected the impact of external factors (e.g., unforeseen shifts in customer activity) affecting our Adjusted EBITDA and Free Cash Flow results. The Board also exercised its discretion to include the impact of the Meritage acquisition in the WCB Program targets and results. Based upon the results described above and in recognition of the Partnership’s overall excellent performance, including exceptional achievement with respect to the Partnership’s core businesses, operational efficiency, and sustainability objectives, the Board approved a payout of 149% under the 2023 WCB Program.


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S16 Discretionary Bonus Pool. In 2023, the Board also approved an additional discretionary bonus pool under the WCB Program (the “S16 Discretionary Bonus Pool”) for the Partnership’s non-CEO Section 16 officers, which includes the other NEOs. The S16 Discretionary Bonus Pool is equal to 20% of the aggregate base salaries of each non-CEO Section 16 officer, and may be funded in an amount of up to 40% of such aggregate base salaries (i.e. 20% multiplied by up to 200%). Any S16 Discretionary Bonus Pool allocations, if any, shall be based on the recommendation of the CEO and Compensation Committee and are subject to the final approval of the Board.
For the S16 Discretionary Bonus Pool, the Board considered the recommendations of the CEO and the Compensation Committee in reviewing the individual performance of the non-CEO Section 16 officers. Based on these recommendations and the Board’s own review, the Board approved a S16 Discretionary Bonus Pool of $0.651 million for the NEOs, allocated as set forth in the table below. The CEO and Compensation Committee’s recommendation for the funding of the S16 Discretionary Bonus Pool was based on the outstanding performance of the non-CEO Section 16 officers (including the NEOs) towards achieving our company goals under the WCB Program. The established pool was allocated to non-CEO Section 16 Officers in recognition of the efforts of: (a) Ms. Shults and Messrs. Bourne and Dial on the Meritage acquisition, (b) Ms. Shults and Mr. Nebreda on the successful management of WES’s capital projects, (c) Mr. Bourne on the achievement of significant commercial successes during the year, and (d) Mr. Nebreda in leading a cross-functional team to implement information-technology systems to align with and streamline our critical work processes.

Actual Bonuses Earned for 2023. The cash bonus awards for 2023 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
2023 WCB Program Corporate Performance Awards ($) (1)
S16 Discretionary Bonus Pool Allocation ($)
Total Cash Bonus
Awards ($)
Mr. Ure1,676,250+
N/A
=1,676,250
Ms. Shults
596,000+156,167=752,167
Mr. Dial596,000+156,167=752,167
Mr. Bourne596,000+156,167=752,167
Mr. Nebreda
596,000+182,194=778,194
_________________________________________________________________________________________
(1)Represents the bonuses attributed to WES’s performance against the performance metrics discussed above, calculated as their target bonus for the year multiplied by the 149% performance factor.

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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. The expenses related to these perquisites are imputed and considered taxable income to the executive officers, as applicable, and no related tax gross-ups are provided. Perquisites provided include reimbursement of financial counseling, tax preparation, and estate planning services expenses up to $4,000 annually, and reimbursement for the cost of personal excess liability insurance. In addition, WES has a leased interest in an aircraft that is used primarily for business travel; however, limited personal use by executive officers, including travel by family or invited guests, is allowed so long as any incremental costs associated with such personal use is reimbursed by the executive under a time-sharing agreement. The incremental costs of the perquisites provided are included in the “All Other Compensation” column and supporting footnotes of the Summary Compensation Table. For 2023, all incremental costs associated with personal travel by a named executive officer were reimbursed to us, such that there was no aggregate incremental cost related to such use.

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;

•An annual target bonus for the year of termination, prorated based on the participant’s date of termination, and paid when annual bonuses are paid to other senior executives of the Partnership;

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

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

•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;

•An annual bonus for the year of termination determined based on the greater of target performance and actual performance, in each instance prorated based on the participant’s date of termination and paid when annual bonuses are paid to other senior executives of the Partnership;

•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.

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. 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 our 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 2023 long-term incentive awards that were granted under 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. These clawback provisions are in addition to the provisions of the Clawback Policy for incentive compensation discussed in the following paragraph.

Clawback Policy. In order to comply with applicable NYSE and SEC rules and to further align the interests of our executives and unitholders, the Board has approved the Clawback Policy. The Clawback Policy requires WES to recover certain incentive-based compensation erroneously awarded to our executives if WES is required to prepare an accounting restatement due to its material noncompliance with applicable financial reporting requirements under the securities laws. This includes any restatement required to correct a material error in previously issued financial statements, or to correct an error that would result in a material misstatement if the error were either corrected in the current period or left uncorrected in the current period. For purposes of the Clawback Policy, incentive-based compensation includes compensation granted, earned or vested based upon WES’s attainment of specified financial reporting metrics. This includes, but is not limited to, bonuses paid under the WCB Program to the extent based on financial reporting metrics, as well as ROA awards, TUR awards, and their associated distribution-equivalent rights. The Clawback Policy applies to all incentive-based compensation received by our executives on or after October 2, 2023. Recovery under the Clawback Policy will generally be limited to incentive-based compensation received by the applicable executive during the three completed fiscal years immediately prior to the date WES is required to prepare the restatement.

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

Compensation Committee Report

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, 2023, 2022, and 2021.
Name and Principal PositionYearSalary
($)
Bonus
($) (1)
Stock
Awards
($) (2)
Non-Equity
Incentive Plan
Compensation
($) (3)
All Other
Compensation
($) (4)
Total
($)
Michael P. Ure2023880,769 1,068,750 6,631,078 607,500 377,560 9,565,657 
President and2022767,308 — 5,034,558 1,520,938 325,201 7,648,005 
Chief Executive Officer2021713,462 416,041 6,259,276 984,659 344,607 8,718,045 
Kristen S. Shults (5)
2023484,615 756,167 2,044,566 216,000 149,836 3,651,184 
Senior Vice President and2022362,731 — 1,807,184 502,400 68,558 2,740,873 
Chief Financial Officer2021— — — — — — 
Christopher B. Dial
2023488,462 536,167 2,044,566 216,000 198,206 3,483,401 
Senior Vice President,2022421,154 — 1,006,937 533,800 123,641 2,085,532 
General Counsel and Secretary2021388,462 137,225 1,459,424 324,775 100,514 2,410,400 
Robert W. Bourne2023488,462 536,167 2,044,566 216,000 243,591 3,528,786 
Senior Vice President and2022421,923 — 1,006,937 533,800 165,975 2,128,635 
Chief Commercial Officer2021405,000 164,670 1,201,841 389,730 181,082 2,342,323 
Alejandro O. Nebreda (5)
2023485,577 562,194 2,042,963 216,000 142,872 3,449,606 
Senior Vice President,
2022— — — — — — 
Business Services
2021— — — — — — 
_________________________________________________________________________________________
(1)    For years 2023 and 2021, this column reflects (i) 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 years ended December 31, 2023 and 2021, and (ii) for 2023, also includes any allocations to the applicable NEO of the S16 Discretionary Bonus Pool, each as discussed in the Compensation Discussion and Analysis. Ms. Shults’ 2023 bonus amount also includes a one-time retention bonus of $220,000 that was paid in 2023.
(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 2023 ROA unit awards as of the grant date for Mr. Ure, Ms. Shults, Mr. Dial, Mr. Bourne, and Mr. Nebreda were approximately $3.0 million, $0.93 million, $0.93 million, $0.93 million, and $0.93 million, respectively. The maximum values, assuming a 200% payout, of the 2023 TUR unit awards as of the grant date for Mr. Ure, Ms. Shults, Mr. Dial, Mr. Bourne, and Mr. Nebreda were approximately $4.3 million, $1.3 million, $1.3 million, $1.3 million, and $1.3 million, respectively.. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For information regarding the awards granted in 2023, see the Grants of Plan-Based Awards in 2023 table.
(3)    This column reflects the portion of the annual cash bonus awards calculated based on our unadjusted performance results, pursuant to the WCB Program.
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(4)    The 2023 amounts are detailed in the table below:
NamePayments by the Partnership to Employee 401(k) Plan and Savings Restoration Plan ($)
Financial/Tax/Estate Planning ($)
Other ($) (i)
Total ($)
Michael P. Ure360,256 3,145 14,159 377,560 
Kristen S. Shults
138,182 500 11,154 149,836 
Christopher B. Dial
153,340 4,000 40,866 198,206 
Robert W. Bourne194,230 4,000 45,361 243,591 
Alejandro O. Nebreda
110,537 6,181 26,154 142,872 
_________________________________________________________________________________________
(i)    Amounts reflect cash payments under a one-time all-employee PTO buyback program, pursuant to which employees were compensated for PTO hours that would have otherwise been forfeited for the year.
(5)    Ms. Shults was not an NEO for the year ended December 31, 2021. Mr. Nebreda was not an NEO for the years ended December 31, 2022 and 2021.

Grants of Plan-Based Awards in 2023

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 Partners, LP 2017 Long-Term Incentive Plan during 2023 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. These values exclude any allocation of the S16 Discretionary Bonus Pool to the applicable NEO.

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, 2025. 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, 2024. 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
($) (3)
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts Under
Equity Incentive Plan Awards
Name and 
Award Type		Grant DateThreshold
($)		Target
($)
Maximum
($) (1)
Threshold
(#) (2)
Target
(#)
Maximum
(#)
Michael P. Ure— — 1,125,000 — — — — — — 
Time-Based Units02/14/2023— — — — — — 105,263 2,999,996 
ROA Units02/14/2023— — — 13,158 52,632 105,264 — 1,500,012 
TUR Units02/14/2023— — — 30,527 52,632 105,264 — 2,131,070 
Kristen S. Shults
— — 400,000 — — — — — — 
Time-Based Units02/14/2023— — — — — — 32,456 924,996 
ROA Units02/14/2023— — — 4,057 16,228 32,456 — 462,498 
TUR Units02/14/2023— — — 9,412 16,228 32,456 — 657,072 
Christopher B. Dial— — 400,000 — — — — — — 
Time-Based Units02/14/2023— — — — — — 32,456 924,996 
ROA Units02/14/2023— — — 4,057 16,228 32,456 — 462,498 
TUR Units02/14/2023— — — 9,412 16,228 32,456 — 657,072 
Robert W. Bourne— — 400,000 — — — — — — 
Time-Based Units02/14/2023— — — — — — 32,456 924,996 
ROA Units02/14/2023— — — 4,057 16,228 32,456 — 462,498 
TUR Units02/14/2023— — — 9,412 16,228 32,456 — 657,072 
Alejandro O. Nebreda
— — 400,000 — — — — — — 
Time-Based Units02/16/2023— — — — — — 32,593 924,989 
ROA Units
02/16/2023
— — — 4,074 16,297 32,594 — 462,509 
TUR Units02/16/2023— — — 9,452 16,297 32,594 — 655,465 
_________________________________________________________________________________________
(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. These values exclude any allocation of the S16 Discretionary Bonus Pool to the applicable NEO.
(2)The threshold payout disclosed is 25% of target for the ROA awards and 58% of target for the TUR awards. For the TUR awards, if during the performance period a company is removed from the peer group, then the percentile ranking and threshold payout would be recalculated using the remaining companies, with the threshold payout beginning at 50% of target at the 25th percentile ranking.
(3)The amounts reflect the fair value on the grant date of the awards made to the NEOs in 2023 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


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Outstanding Equity Awards at Year-End 2023

The following table reflects outstanding equity awards for each NEO as of December 31, 2023. The market values shown are based on WES’s closing unit price of $29.26 on December 29, 2023.
 Unit Awards
Equity Incentive Plan Awards
Restricted Units (1)
Performance Units (2) (3)
 Number of
Units That Have
Not Vested
(#)		Market Value of Units That Have
Not Vested
($)		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 Units205,048 5,999,704 — — 
ROA Units— — 363,852 10,646,310 
TUR Units— — 264,758 7,746,819 
Kristen S. Shults
Time-Based Units66,603 1,948,804 — — 
ROA Units— — 48,591 1,421,773 
TUR Units— — 27,505 804,796 
Christopher B. Dial
Time-Based Units52,938 1,548,966 — — 
ROA Units— — 90,937 2,660,817 
TUR Units— — 64,942 1,900,203 
Robert W. Bourne
Time-Based Units51,364 1,502,911 — — 
ROA Units— — 82,750 2,421,265 
TUR Units— — 57,856 1,692,867 
Alejandro O. Nebreda
Time-Based Units62,680 1,834,017 — — 
ROA Units— — 28,520 834,495 
TUR Units— — 14,016 410,108 
_________________________________________________________________________________________
(1)The table below shows the vesting dates for the respective time-based units listed in the above Outstanding Equity Awards at Year-End 2023 Table:
Vesting DateMr. UreMs. ShultsMr. DialMr. BourneMr. Nebreda
02/12/2024105,970 29,454 25,519 23,945 29,478 
02/12/202563,990 26,330 16,600 16,600 22,337 
02/12/202635,088 10,819 10,819 10,819 10,865 
(2)The table below shows the performance periods for the respective ROA Units listed in the above Outstanding Equity Awards at Year-End 2023 Table. The number of outstanding ROA Units for each award is calculated based on WES’s return-on-assets performance as of December 31, 2023, 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, 2023, WES’s performance under the ROA awards was 173.3%, 186.3%, and 175.0% for the performance periods ending December 31, 2023, 2024, and 2025, respectively.
Performance PeriodMr. UreMs. ShultsMr. DialMr. BourneMr. Nebreda
1/1/2021 to 12/31/2023 (i)
190,979 — 46,383 38,196 — 
1/1/2022 to 12/31/202480,767 20,192 16,155 16,155 — 
1/1/2023 to 12/31/202592,106 28,399 28,399 28,399 28,520 
_______________________________________________________________
(i)    Payment of these awards, earned for the performance period ending December 31, 2023, were made in February 2024 after the Board’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.
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(3)The table below shows the performance periods for the respective TUR Units listed in the above Outstanding Equity Awards at Year-End 2023 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, 2023, 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, 2023, WES’s performance under the TUR awards was 150%, 125%, and 86% for the performance periods ending December 31, 2023, 2024, and 2025, respectively.
Performance PeriodMr. UreMs. ShultsMr. DialMr. BourneMr. Nebreda
1/1/2021 to 12/31/2023 (i)
165,302 — 40,146 33,060 — 
1/1/2022 to 12/31/202454,192 13,548 10,839 10,839 — 
1/1/2023 to 12/31/2025 (ii)
45,264 13,957 13,957 13,957 14,016 
________________________________________________________________
(i)    Payment of these awards, earned for the performance period ending December 31, 2023, were made in February 2024 after the Board’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.
(ii)    The TUR Units outstanding for the performance period ending December 31, 2025, as listed in the table above, assume that any Impacted Peer(s) have been dropped to the bottom of the relative peer group ranking for purposes of determining WES’s relative total unitholder return performance ranking. The treatment of Impacted Peers is discussed further in the Compensation Discussion and Analysis.

Option Exercises and Units Vested in 2023

The following table reflects information about the aggregate dollar value realized during 2023 by our NEOs for WES awards that vested in 2023.
 Unit Awards
Name
Number of Units 
Acquired on Vesting
(#) (1)
Value Realized
on Vesting
($) (2)
Michael P. Ure272,155 7,726,345 
Kristen S. Shults23,246 656,932 
Christopher B. Dial56,013 1,589,986 
Robert W. Bourne60,444 1,716,370 
Alejandro O. Nebreda
38,598 1,090,779 
_________________________________________________________________________________________
(1)The number of units acquired on vesting includes the time-based units that vested in 2023 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.


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Pension Benefits for 2023

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.

Nonqualified Deferred Compensation for 2023

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 Program 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 2023
Partnership Contributions in 2023 (1)
Aggregate Earnings / Losses in 2023
Aggregate Withdrawal / Distributions in 2023
Aggregate Balance at End of 2023 (2)
Michael P. Ure$— $316,756 $19,049 $— $765,958 
Kristen S. Shults
— 94,682 4,430 — 124,975 
Christopher B. Dial— 109,840 20,368 — 254,531 
Robert W. Bourne— 150,730 22,140 — 374,213 
Alejandro O. Nebreda
— 74,237 8,679 — 131,521 
_________________________________________________________________________________________
(1)Reflects contributions earned for fiscal year 2023, although not credited to participant accounts until 2024. These contributions are reported in the Summary Compensation Table for each of the NEOs under the “All Other Compensation” column for the year 2023.
(2)The balance for each NEO includes Partnership contributions previously reported in the Summary Compensation Table for fiscal years prior to 2023 in the following aggregate amounts: Mr. Ure - $445,845; Ms. Shults - $25,863; Mr. Dial - $130,946; Mr. Bourne - $209,120; Mr. Nebreda - $0.

Potential Payments Upon Termination or Change of Control

As of December 31, 2023, all of our NEOs were eligible for severance benefits under the ESP and CIC Plan. 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, 2023 and, where applicable, using the closing price of our common unit of $29.26 (as reported on the NYSE as of December 29, 2023). 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 2023 Table.

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. Bourne
Mr. Nebreda
Cash Severance $— $— $— $— $— 
Total$— $— $— $— $— 


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Involuntary Not For Cause Termination or Good Reason Termination under the ESP. As of December 31, 2023, the NEOs below were eligible for severance benefits 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. Bourne
Mr. Nebreda
Cash Severance (1)
$4,050,000 $1,350,000 $1,350,000 $1,350,000 $1,350,000 
Pro-Rata Annual Cash Bonus (2)
1,125,000 400,000 400,000 400,000 400,000 
Pro-Rata Vesting of WES Equity Awards (3)
17,130,940 1,828,516 4,127,972 3,640,471 1,173,824 
Continuation of Welfare Benefits (4)
60,631 42,117 15,967 45,267 58,884 
Total$22,366,571 $3,620,633 $5,893,939 $5,435,738 $2,982,708 
_________________________________________________________________________________________
(1)Reflects amounts 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, Bourne, and Nebreda reflect 1.5 times the sum of their current base salary plus target bonus.
(2)The amounts reflect a prorated annual target bonus, assuming each NEO’s employment terminated on December 31, 2023.
(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, 2023. In the event of an involuntary termination not for cause or a “Good Reason” termination, the performance units would be paid after the end of the performance period, based on actual performance. Amounts include the value of the 2021 annual performance unit awards with performance periods that ended December 31, 2023, but were not settled until February 2024.
(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.

Change of Control: Involuntary Termination or Voluntary For Good Reason. The following table reflects benefits payable under the CIC Plan to the NEOs in the event of (i) a change of control of WES and (ii) a subsequent qualifying termination event.
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.
Mr. UreMs. ShultsMr. DialMr. Bourne
Mr. Nebreda
Cash Severance (1)
$6,054,750 $1,800,000 $1,800,000 $1,800,000 $1,800,000 
Pro-Rata Annual Cash Bonus (2)
1,676,250 596,000 596,000 596,000 596,000 
Accelerated Vesting of WES Equity Awards (3)
24,608,421 4,241,822 6,176,434 5,683,491 3,145,362 
Continuation of Welfare Benefits (4)
60,631 42,117 15,967 45,267 58,884 
Total$32,400,052 $6,679,939 $8,588,401 $8,124,758 $5,600,246 
_________________________________________________________________________________________
(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, and Messrs. Dial, Bourne, and Nebreda are calculated as 2.0 times 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 2023 under the WCB Program, as discussed in the Compensation Discussion and Analysis and exclude any amounts awarded under the S16 Discretionary Bonus Pool.
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(3)The amounts reflect the estimated current value of unvested time-based units and unvested performance units, based on performance to date, unless performance to date was below target, in which case we have assumed target performance, all as of December 31, 2023. 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 the 2021 annual performance unit awards with performance periods that ended December 31, 2023, but were not settled until February 2024.
(4)The amounts reflect the continuation of welfare benefits for two years at employee rates. The NEOs are also eligible for reimbursement of outplacement services for up to nine months following their separation.

Death or Termination due to Disability
Mr. UreMs. ShultsMr. DialMr. Bourne
Mr. Nebreda
Accelerated Vesting of WES Equity Awards (1)
$24,392,833 $4,175,373 $6,109,986 $5,617,043 $3,078,620 
Total$24,392,833 $4,175,373 $6,109,986 $5,617,043 $3,078,620 
______________________________________________________________________________________
(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, 2023. 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 the 2021 annual performance unit awards with performance periods that ended December 31, 2023, but were not settled until February 2024.

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 2023 calendar year, the annual total compensation of Mr. Ure, as reported in the Summary Compensation Table for this Item 11, was $9,565,657. The annual total compensation for our median employee, calculated using the same methodology used for our NEOs in the Summary Compensation Table was $155,035. Based on this information, for 2023, Mr. Ure’s total annual compensation was 62 times the annual total compensation of the median employee. In preparing this pay ratio disclosure, we took the following steps:

•We determined that, as of December 31, 2023, our employee population consisted of 1,366 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 compliance with the regulations, we are utilizing a new median employee after using the same one for the prior three years. We identified the median employee for 2023 by using base salary earnings for all employees, excluding our CEO, who were employed by us on December 31, 2023. We included all employees, whether employed on a full-time or part-time basis and did not make any estimates, assumptions, or adjustments to the data in identifying the median employee. The methodology used in identifying the median employee is consistent with the methodology we used in prior years.

•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 2023.

•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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Accounting Restatements and Recovery Actions Under Clawback Policy

Item 402(w) of Regulation S-K (“Item 402(w)”) requires the Partnership to make certain disclosures in the event the Partnership is required to prepare an accounting restatement. As of December 31, 2023, the Partnership has not been required to prepare an accounting restatement. Therefore, no disclosures under Item 402(w) are required.

Option Awards and Material Nonpublic Information

Item 402(x) of Regulation S-K (“Item 402(x)”) requires the Partnership to disclose certain policies and practices regarding option awards, including how the Board takes material nonpublic information into account when determining the timing and terms of option awards. The Partnership does not issue option awards. Therefore, no disclosures under Item 402(x) are required.

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 2023, 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 2023 annual review of director compensation, the Board directly retained Zayla Partners to provide benchmark compensation data and recommendations for the design of our non-employee director compensation program for the 2023 calendar year. Following such review, no changes to director compensation were recommended for 2023.
Accordingly, compensation for non-employee directors during 2023 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 2023 by each non-employee director:
NameFees Earned or Paid in Cash
($)
Stock
Awards 
($) (1)
Total
($)
Oscar K. Brown134,000 145,008 279,008 
Kenneth F Owen134,000 145,008 279,008 
David J. Schulte134,000 145,008 279,008 
Lisa A. Stewart136,000 145,008 281,008 
________________________________________________________________________________________
(1)The amounts included in the Stock Awards column represent the grant date fair value of phantom units made to directors in 2023, computed in accordance with FASB ASC Topic 718, based on the value of our common units on grant date. See the table below for phantom units awarded to each non-employee director during 2023. As of December 31, 2023, Messrs. Brown, Owen, and Schulte and Ms. Stewart each had 5,088 outstanding phantom units.
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The table below contains the grant date fair value of phantom unit awards made to each non-employee director during 2023:
NameGrant Date
Phantom 
Units 
(#) (1)
Grant Date Fair 
Value of Stock Awards
($) (2)
Oscar K. BrownFebruary 145,088 145,008 
Kenneth F OwenFebruary 145,088 145,008 
David J. SchulteFebruary 145,088 145,008 
Lisa A. StewartFebruary 145,088 145,008 
_________________________________________________________________________________________
(1)The phantom units granted on February 14, 2023, will vest in full on February 12, 2024, 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 2023 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 14, 2024:

•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)
185,181,578 48.7%
Peter J. Bennett— *
Michael P. Ure (3)
556,404 *
Kristen S. Shults40,997 *
Robert W. Bourne129,271 *
Christopher B. Dial132,602 *
Alejandro O. Nebreda
64,357 *
Oscar K. Brown (4)
27,791 *
Nicole E. Clark — *
Frederick A. Forthuber — *
Kenneth F. Owen 25,730 *
David J. Schulte 30,230 *
Lisa A. Stewart 25,730 *
All directors and executive officers
as a group (12 persons)		1,033,112 *
_________________________________________________________________________________________
*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)Occidental is the ultimate parent company of each of the following entities and may, therefore, be deemed to beneficially own the units held by such entities. Western Gas Resources, Inc. owns 156,219,520 common units, APC Midstream Holdings, LLC owns 457,849 common units, WGRAH owns 14,139,260 common units, and Anadarko USH1 Corporation owns 14,364,949 common units of WES.
(3)Common units held in a margin account. However, there are currently no margin borrowings associated with this account.
(4)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
32,322,784 (1)
8.52%
Common Units
Invesco Ltd.
1331 Spring Street NW, Suite 2500
Atlanta, GA 30309
23,514,801 (2)
6.20%
_________________________________________________________________________________________
(1)Based upon its Schedule 13G/A filed February 5, 2024, with the SEC with respect to Partnership securities held as of December 31, 2023, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 32,322,784 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 32,151,085 of the common units held by ALPS.
(2)Based upon its Schedule 13G filed February 9, 2024, with the SEC with respect to Partnership securities held as of December 31, 2023, Invesco Ltd. has shared voting power as to 23,514,801 common units and dispositive power as to 23,347,060 common units.

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, 2023. 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
2,160,727 (1)
— (2)
10,706,523 
Equity compensation plans not approved by security holders
524,422 (1)
— (2)
— 
Total2,685,149 — 10,706,523 
_________________________________________________________________________________________
(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 14, 2024, Occidental held (i) 185,181,578 of our common units, representing a 47.5% 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,
thousands202320222021
Revenues and other
Service revenues – fee based$1,773,914 $1,674,959 $1,589,367 
Service revenues – product based16,497 56,907 11,888 
Product sales43,683 63,367 31,103 
Total revenues and other1,834,094 1,795,233 1,632,358 
Equity income, net – related parties (1)
152,959 183,483 204,645 
Operating expenses
Cost of product (2)
(72,903)(25,447)42,805 
Operation and maintenance4,618 5,081 27,805 
General and administrative (3)
284 2,338 15,613 
Total operating expenses(68,001)(18,028)86,223 
Gain (loss) on divestiture and other, net— (1,756)420 
_________________________________________________________________________________________
(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)Balances for the years ended December 31, 2022 and 2021, include 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. Balances for the year ended December 31, 2021, also includes 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,
thousands20232022
Assets
Accounts receivable, net$358,141 $313,937 
Other current assets1,260 1,578 
Equity investments (1)
904,535 944,696 
Other assets43,216 29,058 
Total assets1,307,152 1,289,269 
Liabilities
Accounts and imbalance payables38,541 32,150 
Accrued liabilities4,979 11,756 
Other liabilities (2)
335,320 268,399 
Total liabilities378,840 312,305 
_________________________________________________________________________________________
(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 contract liabilities from contracts with customers. See Note 2—Revenue from Contracts with Customers 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,
thousands202320222021
Distributions from equity-investment earnings – related parties$155,169 $186,153 $213,516 
Capital expenditures— (470)(2,000)
Proceeds from the sale of assets to related parties— 200 — 
Contributions to equity investments - related parties(1,153)(9,632)(4,435)
Distributions from equity investments in excess of cumulative earnings – related parties39,104 63,897 41,385 
Distributions to Partnership unitholders (1)
(494,127)(372,468)(272,192)
Distributions to WES Operating unitholders (2)
(22,850)(24,898)(14,984)
Net contributions from (distributions to) related parties— 1,423 8,533 
Unit repurchases from Occidental (3)
(127,500)(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)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 materially from our consolidated financial statements:

Consolidated statements of operations
Year Ended December 31,
thousands202320222021
General and administrative (1)
$3,554 $5,373 $18,365 
_________________________________________________________________________________________
(1)Includes an intercompany service fee between WES and WES Operating. Balances for the years ended December 31, 2022 and 2021, include 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. The balance for the year ended December 31, 2021, also include amounts charged by Occidental pursuant to the shared service agreement (see Services Agreement within this Item 13).

Consolidated balance sheets
December 31,
thousands20232022
Other current assets$1,235 $1,487 
Other assets41,405 28,459 
Accounts and imbalance payables (1)
69,472 76,131 
Accrued liabilities4,662 11,439 
_________________________________________________________________________________________
(1)Includes balances related to transactions between WES and WES Operating.

Consolidated statements of cash flows
Year Ended December 31,
thousands202320222021
Distributions to WES Operating unitholders (1)
$(1,142,217)$(1,244,533)$(749,018)
_________________________________________________________________________________________
(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, 2023, production owned or controlled by Occidental represented 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% 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 is not liable for any obligations under the Brasada gas processing agreement after June 30, 2023. For all periods presented, Mesquite 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.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for field-related costs, shared field offices, and easements (see Related-party commercial agreement below) supporting our operations at certain 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 section above. Related-party expenses bear no direct relationship to related-party revenues, and third-party expenses bear no direct relationship to third-party revenues.

Services Agreement. Occidental performed certain centralized corporate functions for us and WES Operating pursuant to the agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP (“Services Agreement”). Most of the administrative and operational services previously provided by Occidental fully transitioned to us by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

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.

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. Also, as a result of the amendments under the CUA, these agreements are 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 through 2038, the remaining term of the agreements.


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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, 2023, 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
thousands2023202220232022
Audit fees$575 $250 $2,905 $2,673 
Total$575 $250 $2,905 $2,673 

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 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 2023, 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 2023, 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, 2024.

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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
184
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
185
Exhibit
Number		Description
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.25
4.26
10.1
10.2
‡10.3
186
Exhibit
Number		Description
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
‡10.12
‡10.13
‡10.14
‡10.15
‡10.16
‡10.17
†10.18
10.19
187
Exhibit
Number		Description
1020
10.21
†10.22
†10.23
†10.24
†10.25
†10.26
†10.27
†10.28
*21.1
*23.1
*23.2
24.1
*31.1
*31.2
*31.3
*31.4
**32.1
**32.2
188
Exhibit
Number		Description
‡97.1
*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 21, 2024
/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 21, 2024
/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 21, 2024
/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 21, 2024
/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.

190
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 21, 2024.

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

191