Western Midstream Partners, LP 10-K

wes-20251231 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 , 2025 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, LP 001-35753 Delaware 46-0967367 Western Midstream Operating, LP 001-34046 Delaware 26-1075808 Address of principal executive offices: Zip Code: Registrant’s telephone number, including area code: Western Midstream Partners, LP 9950 Woodloch Forest Drive, Suite 2800 The Woodlands, Texas 77380 (346) 786-5000 Western Midstream Operating, LP 9950 Woodloch Forest Drive, Suite 2800 The Woodlands, Texas 77380 (346) 786-5000 Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading symbol Name of exchange on which registered Western Midstream Partners, LP Common units WES New York Stock Exchange Western Midstream Operating, LP None None None 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, LP Yes þ No ¨ Western Midstream Operating, LP Yes 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, LP Yes ¨ No þ Western Midstream Operating, LP Yes ¨ 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, LP Yes þ No ¨ Western Midstream Operating, LP Yes 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, LP Yes þ No ¨ Western Midstream Operating, LP Yes 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, LP Large Accelerated Filer Accelerated Filer Non-accelerated Filer Smaller Reporting Company Emerging Growth Company þ ☐ ☐ ☐ ☐ Western Midstream Operating, LP Large Accelerated Filer Accelerated Filer Non-accelerated Filer Smaller Reporting Company Emerging 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, LP Yes ☐ No þ Western Midstream Operating, LP Yes ☐ 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, 2025, based on the closing price as reported on the New York Stock Exchange. Western Midstream Partners, LP $ 8.3 billion Western Midstream Operating, LP None Common units outstanding as of February 13, 2026: Western Midstream Partners, LP 393,667,434 Western Midstream Operating, LP None DOCUMENTS INCORPORATED BY REFERENCE None Auditor Name Auditor Location Auditor Firm ID Western Midstream Partners, LP KPMG LLP Houston, Texas 185 Western Midstream Operating, LP KPMG LLP Houston, Texas 185 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 TABLE OF CONTENTS Item Page PART I 1 and 2. Business and Properties 8 General Overview 8 Assets and Areas of Operation 9 Acquisitions and Divestitures 11 Strategy 11 Competitive Strengths 12 WES and WES Operating’s Relationship with Occidental Petroleum Corporation 13 Properties 14 Competition 26 Regulation of Operations 26 Environmental Matters and Occupational Health and Safety Regulations 28 Title to Properties and Rights-of-Way 32 Human Capital Resources 32 1A. Risk Factors 33 1B. Unresolved Staff Comments 49 1C. Cybersecurity 49 3. Legal Proceedings 49 4. Mine Safety Disclosures 49 PART II 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities 50 Market Information 50 Other Securities Matters 50 Selected Information From Our Partnership Agreement 51 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 52 Executive Summary 52 Our Operations 54 How We Evaluate Our Operations 54 Items Affecting the Comparability of Our Financial Results 55 Results of Operations 55 Operating Results 56 Reconciliation of Non-GAAP Financial Measures 62 Key Performance Metrics 66 General Trends and Outlook 66 Liquidity and Capital Resources 68 Items Affecting the Comparability of Financial Results with WES Operating 72 Critical Accounting Estimates 74 Recent Accounting Developments 75 7A. Quantitative and Qualitative Disclosures About Market Risk 76 8. Financial Statements 77 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 133 9A. Controls and Procedures 133 9B. Other Information 133 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 134 4 Table of Contents Item Page PART III 10. Directors, Executive Officers, and Corporate Governance 135 11. Executive Compensation 143 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 171 13. Certain Relationships and Related Transactions, and Director Independence 173 14. Principal Accounting Fees and Services 179 PART IV 15. Exhibits, Financial Statement Schedules 179 16. Form 10-K Summary 185 5 Table of Contents 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 Term Definition Aris Aris Water Solutions, Inc., which was acquired by the Partnership on October 15, 2025. Barrel, Bbl, Bbls/d, MBbls/d 42 U.S. gallons measured at 60 degrees Fahrenheit, barrels per day, thousand barrels per day. Board The board of directors of WES’s general partner. Chipeta Chipeta Processing, LLC, in which we are the managing member and own a 75% interest. Chipeta LLC agreement Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009. Condensate A natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions. DBM water systems Produced-water gathering, transporting, recycling, treating, supply, and disposal systems in West Texas and New Mexico, including the assets acquired from Aris (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). Delivery point The point where hydrocarbons are delivered by a processor or transporter to a producer, shipper, or purchaser, typically the inlet at the interconnection between the gathering or processing system and the facilities of a third-party processor or transporter. DJ Basin complex The Platte Valley, 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 Act The Securities Exchange Act of 1934, as amended. 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 that we sold in April 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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. MIGC MIGC, LLC. Mi Vida Mi Vida JV LLC, in which we own a 50% interest. MLP Master limited partnership. MMBtu Million British thermal units. Mont Belvieu JV Enterprise EF78 LLC, in which we owned a 25% interest that we sold in February 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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. 6 Table of Contents Defined Term Definition NYSE New York Stock Exchange. Occidental Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner. OTTCO Overland Trail Transmission, LLC. Panola Panola Pipeline Company, LLC, in which we owned a 15% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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. RCF WES Operating’s $2.0 billion senior unsecured revolving credit facility. Recycled water Water from industrial processes, such as produced water from wells or flowback from hydraulic fracturing, which has been treated to a standard suitable for reuse in other operations. 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 owned a 20% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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, between WES Operating GP and Occidental. Skim oil A crude-oil byproduct that is recovered during the produced-water gathering and disposal process. Springfield system The Springfield gas - gathering system and Springfield oil - gathering system. Stabilization The process to reduce the volatility of a liquid hydrocarbon stream by separating very light hydrocarbon gases, methane and ethane in particular, from heavier hydrocarbon components. This process reduces the volatility of the liquids during transportation and storage. Tailgate The point at which processed natural gas and/or natural-gas liquids leave a processing facility for end-use markets. TEG Texas Express Gathering LLC, in which we own a 20% interest. TEP Texas Express Pipeline LLC, in which we own a 20% interest. Water solutions volumes Water solutions volumes include groundwater and gathered produced water that is treated and recycled. 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 owned a 20% interest that we sold in February 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). Whitethorn A crude - oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC. 2025 Purchase Program The $250.0 million buyback program ending December 31, 2026. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. 7 Table of Contents PART 1 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. As of December 31, 2025, WES owns, directly and indirectly, a 98.1% 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 partnership interest in WES Operating (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, transporting, recycling, treating, supplying, and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell residue, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. Our gas 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, transporting, recycling, treating, supply, and disposal systems provide the link between well sites or nearby collection points and our integrated network of facilities that (i) remove hydrocarbon products and other sediments from produced water, (ii) recycle and supply treated produced water and groundwater for use in our customers’ operations, and (iii) re-inject produced water utilizing permitted disposal wells. 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 Sustainability 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. 8 Table of Contents ASSETS AND AREAS OF OPERATION 9 Table of Contents As of December 31, 2025, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems 13 2 1 Treating facilities 43 3 — Processing plants/trains 27 3 1 Produced-water gathering, treating, recycling, and disposal systems 8 — — NGLs pipelines 3 — 4 Natural-gas pipelines 6 — 1 Crude-oil pipelines 2 1 1 These assets and investments are located in Texas, New Mexico, and the Rocky Mountains (Colorado, Utah, and Wyoming). The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2025: Area Asset Type Miles of Pipeline (1) Processing or Treating Capacity (MMcf/d) (1) Processing, Treating, or Disposal Capacity (MBbls/d) (1) Average Throughput for Natural-Gas Assets (MMcf/d) (2) Average Throughput for Crude-Oil and NGLs Assets (MBbls/d) (2) Average Throughput for Produced-Water Assets (MBbls/d) (2) Texas / New Mexico Gathering, Processing, Treating, Disposal, and Recycling 5,141 2,620 6,072 2,453 284 1,608 Transportation 1,307 — — 448 89 — Rocky Mountains Gathering, Processing, and Treating 6,905 3,160 232 2,391 97 — Transportation 1,557 — — 112 54 — Total 14,910 5,780 6,304 5,404 524 1,608 _________________________________________________________________________________________ (1) All system metrics are presented on a gross basis. Includes (i) bypass capacity at the DJ Basin and West Texas complexes and (ii) recycling capacity at the DBM water systems. (2) 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, transporting, recycling, treating, supplying, 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, 2025, 2024, and 2023, and total assets for the years ended December 31, 2025 and 2024. 10 Table of Contents ACQUISITIONS AND DIVESTITURES During the fourth quarter of 2025, we closed on the acquisition of Aris by merger in a transaction valued at $2.0 billion, including the cash and equity merger consideration, Aris’s outstanding debt of $80.0 million in revolving credit facility borrowings that were repaid at closing, and $500.0 million in principal amount of senior notes. Based on Aris shareholder consideration elections, we issued 26.6 million common units and paid $415.0 million in cash, funded with borrowings under the commercial paper program, in exchange for all issued and outstanding shares of Aris common stock. Aris’s water infrastructure assets, located in Lea and Eddy Counties, New Mexico and West Texas, include approximately 830 miles of produced-water pipeline, 1,812 MBbls/d of produced-water handling capacity, 1,560 MBbls/d of water recycling capacity, and 625,000 dedicated acres. During the second quarter of 2024, we closed on the sale of our 33.75% interest in the Marcellus Interest systems. During the first quarter of 2024, we closed on the sale of the following equity investments to third parties: (i) the 25.00% interest in Mont Belvieu JV, (ii) the 20.00% interest in Whitethorn LLC, (iii) the 15.00% interest in Panola, and (iv) the 20.00% interest in Saddlehorn. See Note 3—Acquisitions and Divestitures, Note 5—Equity and Partners’ Capital, and Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. STRATEGY Our mission is to improve lives through safe, sustainable, and efficient energy delivery. Our primary business objective is to create long-term value for our unitholders through continued delivery of profitable operations and increasing returns 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. In support of our mission and 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. • Enhancing our growth through systematic acquisition activity. We intend to continue to be opportunistic in our approach to adding assets, business lines, and geographies that fit with our mission and competencies in a methodical and systematic manner. The purpose of this activity, when combined with organic growth, is to maintain our return-of-capital levels and drive sustainable, long-term distribution growth. • 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. 11 Table of Contents 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 gathering, transporting, recycling, treating, supply, and disposal infrastructure, 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. For the year ended December 31, 2025, and excluding the impact of equity investments, 97% of our wellhead natural-gas volume and 100% of our crude-oil and produced-water throughput were serviced under fee-based contracts. 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 and skim oil that is recovered during the produced-water gathering and disposal process. In addition, we have historically mitigated volumetric risk through minimum-volume commitments and cost-of-service contract structures. For the year ended December 31, 2025, and excluding the impact of equity investments, we had approximately 2.5 Bcf/d for our natural-gas assets, approximately 476 MBbls/d for our crude-oil and NGLs assets, and approximately 1,028 MBbls/d for our produced-water assets that were supported by either minimum-volume commitments with associated deficiency payments or cost-of-service commitments. See Note 18—Subsequent Event in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for discussion of an amendment to the gas gathering agreement between Delaware Midstream LLC, a WES subsidiary, and Anadarko E&P Onshore LLC, a subsidiary of Occidental, that replaces the agreement’s cost-of-service structure with a fixed-fee structure and additional minimum-volume commitments. 12 Table of Contents • 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. The effective borrowing capacity under the RCF was $2.0 billion as of December 31, 2025. Any outstanding commercial paper borrowings reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its 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. 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, 2025, Occidental had a 39.7% limited partner interest in us, a 2.2% general partner interest in us, and a 1.9% limited partner interest in WES Operating. See Note 18—Subsequent Event in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 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 Table of Contents PROPERTIES The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, 2025. GATHERING, PROCESSING, TREATING, AND DISPOSAL Overview - Texas and New Mexico Location Asset Type Processing / Treating Plants Processing / Treating Capacity (MMcf/d) (1) Processing / Treating / Disposal Capacity (MBbls/d) Gathering Systems Pipeline Miles (2) West Texas / New Mexico West Texas complex (3) Gathering, Processing, & Treating 19 2,190 65 3 1,920 West Texas DBM oil system (4) Gathering & Treating 19 — 350 1 674 West Texas / New Mexico DBM water systems (5) Gathering, Transporting, Recycling, Treating, Supply & Disposal — — 5,567 8 1,637 West Texas Mi Vida (6) Processing 1 200 — — — South Texas Brasada complex Gathering, Processing, & Treating 3 230 15 1 58 South Texas Springfield system (7) Gathering & Treating 3 — 75 2 852 Total 45 2,620 6,072 15 5,141 _________________________________________________________________________________________ (1) Includes 215 MMcf/d of bypass capacity at the West Texas complex. (2) 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. (3) The West Texas complex includes the DBM complex, DBJV and Haley systems, and the Ranch Westex processing plant. (4) The DBM oil system includes five central production facilities, two regional oil treating facilities, and three combined oil transfer/treating facilities. (5) The DBM water systems include assets acquired from Aris. (6) We own a 50% interest in Mi Vida, which owns a processing plant operated by a third party. (7) We own a 50.1% interest in the Springfield system and serve as the operator. 14 Table of Contents West Texas and New Mexico West Texas gathering, processing, and treating complex During the year ended December 31, 2025, the North Loving plant was completed, adding 250 MMcf/d of processing capacity to the complex. • Customers. For the year ended December 31, 2025, Occidental’s production represented 43% of the West Texas complex throughput, and the two largest third-party customers provided 29% of the throughput. 15 Table of Contents • 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 within the West Texas complex and to the Mi Vida plant (see below) 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, Lone Star NGL LLC’s pipeline (“Lone Star pipeline”), and Coastal Bend NGL pipeline. • North Loving Train II. We are currently constructing a new cryogenic processing train in the North Loving area of our West Texas complex. The North Loving Train II will have a capacity of 300 MMcf/d and is expected to be completed in the second quarter of 2027. Upon completion, the West Texas complex will have a total processing capacity of 2,490 MMcf/d. DBM oil-gathering system, treating facilities, and storage • Customers. As of December 31, 2025, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2025, Occidental’s production represented 99% 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 systems During the year ended December 31, 2025, the Partnership completed the Aris acquisition (see Acquisitions and Divestitures within these Items 1 and 2 for additional information). • Customers. As of December 31, 2025, DBM water systems throughput was from Occidental and numerous third-party producers, with Occidental’s production representing 61% 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 of produced water via subsurface injection or offload to third-party service providers. The systems’ injection wells are located in Culberson, Loving, Reeves, and Ward Counties in Texas, and Eddy and Lea Counties in New Mexico. 16 Table of Contents • Water Solutions . The DBM water systems now include significant water supply infrastructure from the Aris acquisition. The DBM water systems now manage 1,560 MBbls/d of produced-water recycling capacity and 19,539 MBbls of water storage capacity in New Mexico and Texas. • McNeill Ranch. As part of the Aris acquisition, the Partnership owns or leases 45,700 acres of land stretching over Lea County in New Mexico, and Andrews and Gaines Counties in Texas. • In January 2025, we sanctioned the construction of (i) a 42-mile, 30-inch pipeline with the capacity to transport over 800 MBbls/d of produced water to additional disposal facilities in eastern Loving County within the Delaware Basin, and (ii) three regional clean-water handling facilities with total incremental capacity of approximately 280 MBbls/d. We also executed an agreement for incremental disposal capacity to support the Pathfinder pipeline project which, in addition to the construction of additional disposal facilities in eastern Loving County, will support existing disposal obligations. Construction is expected to be completed by the first quarter of 2027. Mi Vida processing plant • Customers. As of December 31, 2025, Mi Vida plant throughput was from multiple third-party customers. • 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. • During the fourth quarter of 2024, we executed agreements to realign the commercial structure of Mi Vida, which provided us with 100 MMcf/d of dedicated natural-gas processing capacity in the Delaware Basin beginning in mid-2025. 17 Table of Contents South Texas Brasada gathering, stabilization, treating, and processing complex • Customers. For the year ended December 31, 2025, Brasada complex throughput was from one third-party customer. • Supply. Supply of gas and NGLs is sourced from throughput gathered by the Springfield system. • Delivery points. The facility delivers residue gas to the Eagle Ford Midstream system operated by NET Midstream, LLC. Stabilized condensate is delivered to Plains All American Pipeline, and NGLs are delivered to the Enterprise-operated South Texas NGL Pipeline System. Springfield gathering system, stabilization facility, and storage • Customers. For the year ended December 31, 2025, 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. 18 Table of Contents Overview - Rocky Mountains - Colorado and Utah Location Asset Type Processing / Treating Plants Processing / Treating Capacity (MMcf/d) (1) Processing / Treating Capacity (MBbls/d) Gathering Systems Pipeline Miles (2) Colorado DJ Basin complex (3) Gathering, Processing, & Treating 17 1,750 70 2 1,677 Colorado DJ Basin oil system Gathering & Treating 6 — 155 1 462 Utah Chipeta (4) Processing 3 790 — — 4 Total 26 2,540 225 3 2,143 _________________________________________________________________________________________ (1) Includes 250 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, and Latham processing plants, and the Wattenberg gathering system. (4) We are the managing member and own a 75% interest in Chipeta, which owns the Chipeta processing complex. Colorado 19 Table of Contents DJ Basin gathering, treating, and processing complex • Customers. For the year ended December 31, 2025, Occidental’s production represented 56% of the DJ Basin complex throughput, and the two largest third-party customers provided 30% of the throughput. • Supply. The DJ Basin complex is supplied primarily by the Wattenberg field. • Delivery points. As of December 31, 2025, 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 provide access to local NGLs markets. DJ Basin oil-gathering system, stabilization facility, and storage • Customers. As of December 31, 2025, DJ Basin oil system throughput was from Occidental and two third-party producers. For the year ended December 31, 2025, Occidental’s production represented 98% of the total DJ Basin oil system throughput. • 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. 20 Table of Contents Utah Chipeta processing complex During the year ended December 31, 2025, Chipeta completed interconnect facilities to accommodate up to 150 MMcf/d of gas receipts from Kinder Morgan’s Altamont Green River Pipeline. • Customers. For the year ended December 31, 2025, Chipeta complex throughput was from numerous third-party customers, with the five largest customers providing 85% of the throughput. • Supply. Chipeta’s inlet is connected to Caerus Uinta LLC’s gathering system, the MountainWest Pipeline, LLC system (“MountainWest Pipeline”), Three Rivers Gathering, LLC’s system, which is operated by Harvest Midstream, and Kinder Morgan’s Altamont Green River Pipeline. • 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. 21 Table of Contents Overview - Rocky Mountains - Wyoming Location Asset Type Processing / Treating Plants Processing / Treating Capacity (MMcf/d) Processing / Treating Capacity (MBbls/d) Gathering Systems Pipeline Miles (1) Northeast Wyoming Powder River Basin complex (2) Gathering, Processing, & Treating 6 620 7 2 2,685 Southwest Wyoming Granger complex Gathering — — — 1 742 Southwest Wyoming Red Desert complex Gathering — — — 1 1,049 Southwest Wyoming Rendezvous (3) Gathering — — — 1 286 Total 6 620 7 5 4,762 _________________________________________________________________________________________ (1) Includes 120 miles of transportation related to a FERC-regulated NGLs 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. 22 Table of Contents Northeast Wyoming Powder River Basin gathering, processing, and treating complex • Customers. For the year ended December 31, 2025, the three largest third-party customers provided 66% of the throughput, and Occidental’s production represented 3% of the Powder River Basin complex throughput. • Supply. The Powder River Basin complex serves the gas-gathering needs of several conventional and unconventional 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 • Customers. For the year ended December 31, 2025, Granger complex throughput was from numerous third-party customers, with the two largest customers providing 70% of the throughput. • Supply. The Granger complex is supplied by the Moxa Arch, 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, 2025, Red Desert complex throughput was from numerous third-party customers, with the three largest customers providing 55% 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, 2025, 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 Harvest Midstream’s Blacks Fork gas-processing plant, which connects to the MountainWest Pipeline, NWPL, and the Kern River pipeline via the Rendezvous pipeline. 23 Table of Contents TRANSPORTATION 24 Table of Contents Location Asset Type Ownership Interest Pipeline Miles Colorado, Kansas, Oklahoma White Cliffs (1) (2) Oil & NGLs 10.00 % 1,066 Utah GNB NGL (1) NGLs 100.00 % 33 Northeast Wyoming MIGC (1) Gas 100.00 % 243 Southwest Wyoming OTTCO Gas 100.00 % 215 Colorado, Oklahoma, Texas FRP (1) (2) NGLs 33.33 % 452 Texas TEG (2) NGLs 20.00 % 138 Texas TEP (1) (2) NGLs 20.00 % 594 Texas Red Bluff Express (1) (2) Gas 30.00 % 123 Total 2,864 _________________________________________________________________________________________ (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, 2025. Other parties may also ship on the White Cliffs pipeline at FERC-based rates. The pipeline provides crude-oil and NGLs 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. 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, 2025, 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, 2025. Texas Express Pipeline. TEP delivers to Enterprise’s NGLs 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, 2025, the pipeline had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates. Red Bluff Express pipeline. As of December 31, 2025, 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. 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. 25 Table of Contents COMPETITION The midstream services business is extremely competitive, and our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition is primarily 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 are 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, transport, recycle, treat, supply, and dispose of 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 regulated by 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 is an example of proposed and/or final pipeline safety and maintenance regulations or other regulatory initiatives that could have a potentially material impact on our business: • 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. 26 Table of Contents 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 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. FERC oversees various aspects of these assets’ operations, including rates, services, facility certification, capacity management, and market conduct. FERC-regulated pipelines must comply with standards of conduct, transparency, and anti-manipulation rules, with annual reporting and public disclosures required. Both FERC and the Commodity Futures Trading Commission (the “CFTC”) have authority to impose substantial civil penalties for violations of these rules and regulations, potentially in excess of $1.0 million per day. Should we fail to comply with these regulations, we could be subject to substantial penalties and fines. Interstate Liquids-Pipeline Regulation Our interstate liquids pipelines, including GNB NGL, Thunder Creek NGL, FRP, TEP, and White Cliffs, are regulated by FERC as common carriers under federal law. FERC requires that pipeline rates be “just and reasonable” and uses an indexing methodology, reviewed every five years, to adjust rates. Pipelines may seek rate changes through cost-of-service or market-based approaches, and rates can be challenged or suspended pending investigation. FERC’s Revised Policy Statement restricts MLPs from recovering income tax allowances, potentially impacting revenues. The CFTC and the Federal Trade Commission also oversee market conduct and can impose significant penalties for violations, with fines potentially exceeding $1.0 million per day. 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. 27 Table of Contents 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 on 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 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; 28 Table of Contents • 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”); • 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. 29 Table of Contents 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 groundwater. 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, transporting, supply, and produced-water disposal 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 “Physical injection constraints and the adoption of new or more stringent legal standards relating to induced seismic activity could affect our produced-water disposal operations.” The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable, as existing standards are subject to change and new standards continue to evolve. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not have a material adverse effect on our business, financial condition, results of operations, or cash flows in the future, or that new or more stringently applied existing laws and regulations will not materially increase our costs of doing business. Although we are not fully insured against all environmental risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, and claims for damages to property or persons or imposition of penalties resulting from our operations, could have a material adverse effect on our results of operations. The following are examples of proposed and/or final regulations or other regulatory initiatives that could have a potentially material impact on us: • 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,” which have been amended from time to time. 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 would reconsider the December 2020 final action in favor of a more stringent ground-level ozone standard but did not make a final determination and the 2015 NAAQS remains in place. 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. • Standards Requiring Reduction of Methane and Other Emissions by the Oil and Gas Industry. In March 2024, the EPA published New Source Performance Standards (“NSPS”) and Emissions Guidelines (“EGs”), known as Subpart OOOOb and Subpart OOOOc, respectively, which introduce emissions standards for methane and 30 Table of Contents volatile organic compounds (“VOCs”) from certain new, modified, and reconstructed oil and natural-gas production, processing and transmission facilities. Subpart OOOOc will additionally apply new standards to existing facilities. These rules set more stringent standards and requirements for a variety of sources including flares, wells, storage vessels, compressors, pumps, sweetening units, equipment that may leak, and others. Among the many additional requirements, one notable addition is the creation of a Super Emitter Program that, among other things, authorizes the EPA to require the operator to respond when third parties detect and notify the EPA of remotely-detected emissions. Subpart OOOOb generally became effective in May 2024, with rolling compliance dates for certain sources. Subpart OOOOc 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. Any state-implemented rules must be at least as stringent as the federal rules, and regulated entities will be required to comply with state or federal rules within three years after the deadline for state plan submittals. In November 2025, the EPA finalized a rule to extend certain compliance deadlines for Subpart OOOOb and Subpart OOOOc. We cannot predict the full scope of any final 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 implemented requirements for the performance of leak detection programs that require identification and repair of methane leaks at certain oil and natural-gas sources. States are also imposing rules to limit other emissions from oil and gas operations. For example, in November 2025, the Colorado Air Quality Control Commission (“AQCC”) approved new measures to reduce by 50%, compared to 2017 levels, ground-level ozone-forming air pollution emissions from oil and gas operations. Compliance with these rules or with any similar or future federal or state regulation of methane or other emissions from operations could, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs, and could have a material adverse effect on our business, financial condition, and results of operations. • 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. 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 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, although in September 2025, the EPA proposed a rule to eliminate and/or delay certain of these rules. 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. Since that time, the United States has withdrawn then rejoined the Paris Agreement. In January 2025, President Trump signed an executive order to again withdraw from the Agreement, which would become effective in approximately January 2026 and effectively nullify the United States’ economy-wide GHG emissions reductions targets established pursuant to the Paris Agreement. In 2022, Congress enacted the Inflation Reduction Act (the “IRA”), which added Section 136 to the Clean Air Act and imposed the first-ever direct federal “charge” on methane emissions called the “Waste Emissions Charge” (“WEC”) for certain facilities within the oil and natural gas industry. The IRA states that it would apply to methane emissions beginning in 2024, with the first charge for 2024 emissions due in 2025. In March 2025, however, President Trump signed a Congressional Review Act joint resolution, effectively eliminating the WEC rule. While the rule has been invalidated, the IRA’s underlying statutory methane fee still exists, though enforcement is stalled without an implementing regulation. Further, pursuant to legislation, reporting and payment obligations set forth in the IRA have been delayed until 2034 or later. While the Paris Agreement and the WEC rule have been pulled back for now, there is a possibility that future administrations may seek to proceed with the implementation of associated programs and rules. At the state level, the Colorado AQCC adopted a similar rule in February 2024, imposing fees on certain operations for GHG emissions. Colorado also promulgated, or is expected to promulgate, several rules to implement 2021 state legislation requiring the development of air quality regulations that will result in a 31 Table of Contents 20.5% reduction in combustion greenhouse gas emissions from the midstream sector by 2030 as compared to a 2015 baseline. Such rules require, among other things, midstream operators to comply by 2030 with certain emissions caps through various means of emissions reductions and/or the utilization of credits. Further, Colorado previously adopted regulations for methane emissions from certain oil and natural-gas operations, and imposed certain GHG intensity standards, which set numerical limits of carbon dioxide equivalent (“CO 2 e”) emissions per barrel of oil produced. The implementation of substantial limitations on and/or costs associated with GHG emissions, in areas where we conduct operations could result in increased compliance costs, including 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 could 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. TITLE TO PROPERTIES AND RIGHTS-OF-WAY Our real property is either owned in fee title or held through leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We own portions of the land where our plants and other major facilities are located and lease the remainder of the land under long-standing agreements. We believe we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses. 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, 2025, WES employed 1,704 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 2025 voluntary attrition rate was 9%, 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. 32 Table of Contents 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; 33 Table of Contents • 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, 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. 34 Table of Contents 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, transport, recycle, treat, supply, 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, transport, recycle, treat, supply, and/or dispose. For the year ended December 31, 2025, and excluding the impact of equity investments, 60% of Total revenues and other, 36% of our throughput for natural-gas assets, 91% of our throughput for crude-oil and NGLs assets, and 61% 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. 35 Table of Contents 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 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 $2.1 billion in total principal amount 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, 2025, there were no 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 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 their 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. 36 Table of Contents 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 they have dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders. Our profitability may be negatively impacted by inflation in the cost of labor, materials, and services. Although inflation in the United States has declined since 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. Additionally, the Trump administration has increased tariffs on most Chinese imports under its renewed Section 301 and International Emergency Economic Powers Act authorities and has significantly increased national security-based tariffs on steel and aluminum imports, including raising the general tariff rate on most steel and aluminum products. The Trump administration has also imposed and expanded so called ‘reciprocal’ tariffs on a wide range of United States trading partners with which the United States has sizable trade imbalances and has announced or threatened additional increases on imports from Canada, Mexico, and other key partners. These and other import tariffs could substantially increase our operating and capital costs. Although we cannot predict any future inflation trends or the impact of current or future import tariffs, higher operating and capital costs 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 2025 distribution of $0.91000 per unit per quarter, or $3.64000 per unit per year, we require per-quarter available cash of $379.7 million, or $1,518.8 million per year, based on the number of common units outstanding at February 2, 2026. 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. 37 Table of Contents 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. 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. Physical injection constraints and the adoption of new or more stringent legal standards relating to induced seismic activity could affect our produced-water disposal operations. We dispose of produced water generated from oil and natural-gas production operations. In some instances, operational constraints (e.g., increased wellbore pressures or poor reservoir quality) have limited water injectivity in our areas of operation that have resulted in available injection capacity being lower than our permitted capacity. Additionally, the legal requirements 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 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 operational and regulatory developments could result in restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations. Adverse developments in our geographic areas of operation could disproportionately impact our business, results of operations, financial condition, and ability to make cash distributions to our unitholders. Our business and operations are concentrated in a limited number of producing areas. Due to our limited geographic diversification, adverse operational developments, regulatory or legislative changes, or other events in an area in which we have significant operations could have a greater impact on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders than if our operations were more diversified. Our indebtedness may limit our ability to capitalize on acquisitions and other business opportunities or our flexibility to obtain financing. The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”), 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 38 Table of Contents 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-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 39 Table of Contents 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 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 40 Table of Contents 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, transporting, supply, and produced-water disposal 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 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. 41 Table of Contents 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 domestic and international political events), 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 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 42 Table of Contents 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 Aris, which could have an adverse impact on our future results. The Aris acquisition closed on October 15, 2025. The integration of these acquired assets involves 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. 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. 43 Table of Contents 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 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. 44 Table of Contents 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 408,141,366 common units outstanding as of December 31, 2025, with Occidental holding 165,681,578 common units, representing 40.6% of our outstanding common units. Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the impermissible distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from 45 Table of Contents 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 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. 46 Table of Contents 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. 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 47 Table of Contents 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 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. 48 Table of Contents 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 information technology group is led by our Chief Information Officer (“CIO”) . Our CIO has over 20 years of information security and project management experience and has previously served as the lead information technology officer to one publicly traded enterprise and the cybersecurity and infrastructure lead at a separate publicly traded enterprise, both in the energy industry. Reporting to our CIO is a Director of Cybersecurity and Infrastructure (“DCI”). Our DCI has over 20 years of information technology and cybersecurity experience and holds a Certified Information Systems Security Professional certification from the International Information System Security Certification Consortium, an internationally recognized association of cybersecurity professionals . This role oversees an enterprise-wide cybersecurity strategy, policy, standards, architecture, governance, and risk management, ensuring alignment with our overall information technology and infrastructure objectives. The DCI 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 DCI 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, as part of our continuing commitment to cybersecurity education and preparedness, we actively 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. Item 1. Legal Proceedings Solaris Water Midstream, LLC (“Solaris”), a subsidiary of Aris, and certain affiliates are named defendants in Cause No. 23-05-1085, Stateline Operating, LLC and Stateline Royalties, LP vs. Devon Energy Corporation, Stateline Water, LLC, Devon Energy Production Company, LP, Solaris Water Midstream, LLC, Solaris Midstream DB-TX LLC, and Aris Water Solutions, Inc. , in the 143rd District Court, Loving County, Texas, which was filed on May 4, 2023. In this action, Plaintiffs sue Defendants for, among other things, negligence, waste, trespass, and nuisance based on Plaintiffs’ allegations that Defendants’ operations have harmed Plaintiffs’ oil and gas lease through the injection of disposed saltwater. Defendants dispute Plaintiffs’ claims of liability and damages in this matter. Trial is currently scheduled for September 14, 2026. We have elected to use a $1.0 million threshold for disclosing certain proceedings arising under federal, state, or local environmental laws when a government authority is a party and potential monetary sanctions are involved. We believe proceedings under this threshold are not material to our business and financial proceedings. Other than the items listed herein, 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. 49 Table of Contents 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 13, 2026, there were 94 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 14,403,998 units, respectively, of which 737,749 and 11,655,238 units, respectively, remained available for future issuance as of December 31, 2025. 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 2025 Purchase Program during the fourth quarter of 2025: Period Total number of units purchased Average 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, 2025 — $ — — $ 250,000,000 November 1-30, 2025 — — — 250,000,000 December 1-31, 2025 — — — 250,000,000 Total — — — ______________________________________________________________________________________ (1) In 2025, the Board authorized WES to buy back up to $250.0 million of our common units through December 31, 2026. 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. 50 Table of Contents 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, 2025, our general partner owned a 2.2% general partner interest in us, which entitles it to receive cash distributions. Our general partner may own our common units or other equity securities and would be entitled to receive cash distributions on any such interests. 51 Table of Contents 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 2023 items, and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, 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, 2024, as filed with the SEC on February 26, 2025, 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 98.1% partnership interest in WES Operating, as of December 31, 2025. Amounts attributable to noncontrolling interests presented in this Item 7 consist of (i) the 25% third-party interest in Chipeta for all periods presented, and only for natural-gas assets for throughput attributable to WES, and (ii) the 1.9%, 2.0%, and 2.0% limited partner interest in WES Operating as of December 31, 2025, 2024, and 2023, respectively, owned by an Occidental subsidiary. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and 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, transporting, recycling, treating, supplying, and disposing of produced water. In our capacity as a natural - gas processor, we also buy and sell residue, 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, and the Rocky Mountains (Colorado, Utah, and Wyoming). As of December 31, 2025, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems 13 2 1 Treating facilities 43 3 — Processing plants/trains 27 3 1 Produced-water gathering, treating, recycling, and disposal systems 8 — — NGLs pipelines 3 — 4 Natural - gas pipelines 6 — 1 Crude - oil pipelines 2 1 1 Significant financial and operational events during the year ended December 31, 2025, included the following: • On October 15, 2025, we closed on the acquisition of Aris by merger in an equity-and-cash transaction. See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information. • WES Operating completed the public offerings of $1.2 billion in aggregate principal amount of Senior Notes. Net proceeds from these public offerings (i) will be used to repay the 4.650% Senior Notes due 2026, (ii) were used to repay amounts outstanding under its commercial paper program (including borrowings incurred to fund the cash consideration of the Aris acquisition), and (iii) will be used for general partnership purposes, including the funding of capital expenditures. See Debt and Credit Facilities within this Item 7 for additional information. 52 Table of Contents • WES Operating retired the total principal amount outstanding of the 3.100% Senior Notes due 2025 at par value during the first quarter of 2025 and the 3.950% Senior Notes due 2025 at par value during the second quarter of 2025. • Our fourth-quarter 2025 per-unit distribution is unchanged from the third-quarter 2025 per-unit distribution of $0.910. • We completed the start-up of the North Loving plant in late-February 2025, increasing gas processing capacity at the West Texas complex by 250 MMcf/d to a total of 2,190 MMcf/d. The following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2025 2024 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 2,042 1,871 9 % DJ Basin 1,470 1,436 2 % Powder River Basin 437 456 (4) % Equity investments 550 517 6 % Other 905 946 (4) % Total throughput for natural-gas assets 5,404 5,226 3 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 258 243 6 % DJ Basin 97 92 5 % Powder River Basin 27 25 8 % Equity investments 104 144 (28) % Other 38 37 3 % Total throughput for crude-oil and NGLs assets 524 541 (3) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,608 1,147 40 % Total throughput for produced-water assets 1,608 1,147 40 % 53 Table of Contents 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, produced water, and water solutions. 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, transport, recycle, treat, supply, and dispose of produced water. We operate in Texas, New Mexico, Colorado, Utah, and Wyoming, with a substantial portion of our business concentrated in West Texas, New Mexico, and the Rocky Mountains. For example, for the year ended December 31, 2025, and excluding the impact of equity investments, our West Texas / New Mexico and DJ Basin assets provided (i) 58% and 29%, respectively, of Total revenues and other, (ii) 42% and 30%, respectively, of our throughput for natural-gas assets, (iii) 61% and 23%, respectively, of our throughput for crude-oil and NGLs assets, and (iv) all of our throughput for produced-water assets. For the year ended December 31, 2025, and excluding the impact of equity investments, 60% of Total revenues and other, 36% of our throughput for natural-gas assets, 91% of our throughput for crude-oil and NGLs assets, and 61% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts. For the year ended December 31, 2025, and excluding the impact of equity investments, 97% of our wellhead natural-gas volume and 100% of our crude-oil and produced-water throughput 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) 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 facilities and skim oil that is recovered during the produced-water gathering and disposal process. 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 metrics to analyze our financial and operational results, including (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 (i) the successful drilling of new wells by producers that are dedicated to our systems, (ii) recompletions of existing wells connected to our systems, (iii) our ability to secure volumes from new wells drilled on non-dedicated acreage, and (iv) our ability to attract natural-gas, crude-oil, NGLs, produced-water, or water-solutions volumes currently serviced by our competitors. 54 Table of Contents 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, the annual budget, and other companies in the midstream industry. 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 are closely monitored. Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved. ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS Our historical results of operations and cash flows for the periods presented may not be comparable to future or historical 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, 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 and Note 18—Subsequent Event 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 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. During the fourth quarter of 2025, we closed on the acquisition of Aris by merger in a transaction valued at $2.0 billion, including the cash and equity merger consideration, Aris’s outstanding debt of $80.0 million in revolving credit facility borrowings that were repaid at closing, and $500.0 million in principal amount of senior notes. Based on Aris shareholder consideration elections, we issued 26.6 million common units and paid $415.0 million in cash, funded with borrowings under the commercial paper program, in exchange for all issued and outstanding shares of Aris common stock. During the second quarter of 2024, we closed on the sale of our 33.75% interest in the Marcellus Interest systems for proceeds of $206.2 million, resulting in a net gain on sale of $63.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations. During the first quarter of 2024, we closed on the sale of the following equity investments to third parties: (i) the 25.00% interest in Mont Belvieu JV, (ii) the 20.00% interest in Whitethorn LLC, (iii) the 15.00% interest in Panola, and (iv) the 20.00% interest in Saddlehorn. The combined proceeds received in the first quarter of 2024 of $588.6 million includes $5.9 million in pro-rata distributions through closing, resulting in a net gain on sale of $239.7 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 55 Table of Contents RESULTS OF OPERATIONS OPERATING RESULTS The following tables and discussion present a summary of our results of operations: Year Ended December 31, thousands 2025 2024 Total revenues and other (1) $ 3,843,403 $ 3,605,223 Equity income, net – related parties 85,788 112,385 Total operating expenses (1) 2,316,676 2,043,647 Gain (loss) on divestiture and other, net (11,113) 296,771 Operating income (loss) 1,601,402 1,970,732 Interest expense (390,490) (378,513) Gain (loss) on early extinguishment of debt — 5,403 Other income (expense), net 16,629 31,741 Income (loss) before income taxes 1,227,541 1,629,363 Income tax expense (benefit) 15,086 18,111 Net income (loss) 1,212,455 1,611,252 Net income (loss) attributable to noncontrolling interests 31,472 37,681 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,180,983 $ 1,573,571 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, NGLs, and water solutions volumes 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, 2025” refer to the comparison of the year ended December 31, 2025, to the year ended December 31, 2024. Discussion of 2023 items and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, 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, 2024, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com . 56 Table of Contents Throughput Year Ended December 31, 2025 2024 Inc/(Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 375 453 (17) % Processing 4,479 4,256 5 % Equity investments (1) 550 517 6 % Total throughput 5,404 5,226 3 % Throughput attributable to noncontrolling interests 178 174 2 % Total throughput attributable to WES for natural - gas assets 5,226 5,052 3 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 420 397 6 % Equity investments (1) 104 144 (28) % Total throughput 524 541 (3) % Throughput attributable to noncontrolling interests 10 11 (9) % Total throughput attributable to WES for crude - oil and NGLs assets 514 530 (3) % Throughput for produced-water assets (MBbls/d) Gathering, disposal, and water solutions 1,608 1,147 40 % Throughput attributable to noncontrolling interests 30 23 30 % Total throughput attributable to WES for produced - water assets (2) 1,578 1,124 40 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting. (2) Water solutions volumes include groundwater and gathered produced water that is treated and recycled. Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 174 MMcf/d for the year ended December 31, 2025, primarily due to (i) higher volumes at the West Texas, DJ Basin, and Chipeta complexes due to increased production in the areas and (ii) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline beginning in November 2024. These increases were offset partially by (i) lower volumes at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024, (ii) lower volumes at the Springfield gas-gathering system due to decreased production in the area, 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 16 MBbls/d for the year ended December 31, 2025, primarily due to (i) the divestiture of Whitethorn LLC and Saddlehorn in the first quarter of 2024 and (ii) lower volumes on the TEP pipeline. These decreases were offset partially by higher volumes at the DBM oil system due to increased production in the area. Produced-water assets Total throughput attributable to WES for produced - water assets increased by 454 MBbls/d for the year ended December 31, 2025, due to (i) the acquisition of Aris and (ii) higher production. 57 Table of Contents Revenues Year Ended December 31, thousands except percentages and per-unit amounts 2025 2024 Inc/(Dec) Service revenues – fee based $ 3,453,052 $ 3,248,262 6 % Other revenues from customers Service revenues – product based $ 193,866 $ 215,776 (10) % Product sales 194,681 140,100 39 % Total other revenues from customers $ 388,547 $ 355,876 9 % Per - unit gross average sales price: Natural gas (per Mcf) $ 0.90 $ 0.29 NM NGLs (per Bbl) 25.48 28.62 (11) % _________________________________________________________________________________________ NM — Not meaningful Service revenues – fee based Service revenues – fee based increased by $204.8 million for the year ended December 31, 2025, primarily due to increases of (i) $105.6 million at the DBM water systems due to the acquisition of Aris and increased throughput, partially offset by a change in contract terms effective January 1, 2025, (ii) $98.5 million at the West Texas complex primarily due to increased throughput, partially offset by decreased deficiency fees on certain contracts with throughput minimums, (iii) $32.6 million at the DBM oil system due to increased throughput, higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2025, and deficiency fees on certain contracts with increasing throughput minimums, and (iv) $10.1 million at the DJ Basin complex primarily due to increased throughput. These increases were offset partially by decreases of (i) $32.4 million at the Springfield systems due to decreased throughput and lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, (ii) $18.7 million at the DJ Basin oil system due to lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput, and (iii) $11.0 million at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024. Other revenues from customers Other revenues from customers increased by $32.7 million for the year ended December 31, 2025, primarily due to (i) $52.8 million at the West Texas complex due to increased volumes sold and net average prices and (ii) $29.1 million at the DBM water systems due to the acquisition of Aris and increased volumes sold. These increases were offset partially by a decrease of $35.5 million at the DJ Basin complex primarily due to lower volumes sold and average prices. 58 Table of Contents Equity Income, Net – Related Parties Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Equity income, net – related parties $ 85,788 $ 112,385 (24) % Equity income, net – related parties decreased by $26.6 million for the year ended December 31, 2025, primarily due to decreases of $7.6 million and $7.0 million at TEP and Mi Vida, respectively. Cost of Product and Operation and Maintenance Expenses Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Natural-gas purchases $ 33,941 $ 10,586 NM NGLs purchases 240,109 252,591 (5) % Other (67,072) (90,926) 26 % Cost of product 206,978 172,251 20 % Operation and maintenance 915,896 880,568 4 % Total Cost of product and Operation and maintenance expenses $ 1,122,874 $ 1,052,819 7 % Natural-gas purchases Natural-gas purchases increased by $23.4 million for the year ended December 31, 2025, primarily due to (i) higher average prices at the West Texas complex and (ii) increased purchases at the Chipeta complex. NGLs purchases NGLs purchases decreased by $12.5 million for the year ended December 31, 2025, primarily due to a decrease of $17.6 million at the DJ Basin complex due to lower purchased volumes and average prices, partially offset by an increase of $11.1 million due to the acquisition of Aris. Other items Other items increased by $23.9 million for the year ended December 31, 2025, primarily due to changes in imbalance positions at the West Texas and Powder River Basin complexes. Operation and maintenance expense Operation and maintenance expense increased by $35.3 million for the year ended December 31, 2025, primarily due to increases of (i) $48.3 million related to the acquisition of Aris, (ii) $12.4 million in utility expense, and (iii) $6.2 million in land-related costs. These amounts were offset partially by decreases of (i) $7.7 million in chemicals and treating services, (ii) $7.6 million in contract labor and consulting costs, (iii) $6.2 million in mechanical-integrity costs, and (iv) $6.1 million in regulatory and environmental expense. 59 Table of Contents Other Operating Expenses Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) General and administrative $ 398,922 $ 271,526 47 % Property and other taxes 69,342 62,668 11 % Depreciation and amortization 710,778 650,428 9 % Long-lived asset and other impairments 14,760 6,206 138 % Total other operating expenses $ 1,193,802 $ 990,828 20 % General and administrative expenses General and administrative expenses increased by $127.4 million for the year ended December 31, 2025, primarily due to $120.5 million in acquisition-related expenses associated with the Aris transaction, including $104.6 million in severance payments and $15.9 million in professional services for financial advisory, legal, and other professional fees. Depreciation and amortization expense Depreciation and amortization expense increased by $60.4 million for the year ended December 31, 2025, primarily due to (i) $31.2 million in capital projects being placed into service at the West Texas complex and (ii) $21.5 million related to the acquisition of Aris. Long-lived asset and other impairment expense Long - lived asset and other impairment expense increased by $8.6 million for the year ended December 31, 2025, primarily due to a $10.8 million impairment at the Granger complex. Interest Expense Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Long-term and short-term debt $ (387,493) $ (377,850) 3 % Finance lease liabilities (2,182) (2,573) (15) % Commitment fees and amortization of debt-related costs (11,001) (13,305) (17) % Capitalized interest 10,186 15,215 (33) % Interest expense $ (390,490) $ (378,513) 3 % Interest expense increased by $12.0 million for the year ended December 31, 2025, primarily due to increases of (i) $28.2 million of interest incurred on the 5.450% Senior Notes due 2034 that were issued during the third quarter of 2024, (ii) $6.4 million of interest incurred on the 7.250% Senior Notes due 2030 that were assumed as part of the acquisition of Aris during the fourth quarter of 2025, and (iii) $5.0 million due to lower capitalized interest. These increases were offset partially by a decrease of $30.0 million due to senior note repayments during 2025. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7. 60 Table of Contents Other Income (Expense), Net Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Other income (expense), net $ 16,629 $ 31,741 (48) % Other income (expense), net decreased by $15.1 million for the year ended December 31, 2025, primarily due to lower interest income earned on cash investments throughout 2025. Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Income (loss) before income taxes $ 1,227,541 $ 1,629,363 (25) % Income tax expense (benefit) 15,086 18,111 (17) % Effective tax rate 1 % 1 % — % We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. Income tax expense decreased by $3.0 million for the year ended December 31, 2025, primarily due to Texas margin tax liability and federal income tax on activities operated through corporate entities. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 61 Table of Contents 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) income tax benefit, (v) other income, (vi) other items impacting comparability with our core operating performance, 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 our 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 represents the amount of cash that is available in aggregate for distributions, debt repayments, and other general partnership purposes. 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 (i) should not be considered as alternatives to the comparable GAAP measures or any other measure of financial performance presented in accordance with GAAP, (ii) have important limitations as analytical tools because they exclude some, but not all, items that affect the comparable GAAP measures, (iii) should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP, and (iv) 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 our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences, 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. 62 Table of Contents The following tables present reconciliations of the GAAP measure to our non-GAAP measures: Year Ended December 31, thousands 2025 2024 Reconciliation of Gross margin to Adjusted Gross Margin Total revenues and other $ 3,843,403 $ 3,605,223 Less: Cost of product 206,978 172,251 Depreciation and amortization 710,778 650,428 Gross margin 2,925,647 2,782,544 Add: Distributions from equity investments 122,364 142,236 Depreciation and amortization 710,778 650,428 Less: Reimbursed electricity-related charges recorded as revenues 125,551 117,906 Adjusted Gross Margin attributable to noncontrolling interests 83,681 80,509 Adjusted Gross Margin $ 3,549,557 $ 3,376,793 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 amounts 2025 2024 Gross margin Gross margin for natural - gas assets (1) $ 2,113,810 $ 2,073,533 Gross margin for crude - oil and NGLs assets (1) 407,211 395,886 Gross margin for produced - water assets (1) 435,501 341,784 Per - Mcf Gross margin for natural - gas assets (2) 1.07 1.08 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 2.13 2.00 Per - Bbl Gross margin for produced - water assets (2) 0.74 0.81 Adjusted Gross Margin Adjusted Gross Margin for natural - gas assets $ 2,471,011 $ 2,411,438 Adjusted Gross Margin for crude - oil and NGLs assets 564,461 570,476 Adjusted Gross Margin for produced - water assets 514,085 394,879 Per - Mcf Adjusted Gross Margin for natural - gas assets (3) 1.30 1.30 Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (3) 3.01 2.94 Per - Bbl Adjusted Gross Margin for produced - water assets (3) 0.89 0.96 _________________________________________________________________________________________ (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. 63 Table of Contents Year Ended December 31, thousands 2025 2024 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,212,455 $ 1,611,252 Add: Distributions from equity investments 122,364 142,236 Non-cash equity-based compensation expense (1) 50,803 37,994 Interest expense 390,490 378,513 Income tax expense 15,086 18,111 Depreciation and amortization 710,778 650,428 Long-lived asset and other impairments 14,760 6,206 Other expense 303 248 Less: Gain (loss) on divestiture and other, net (11,113) 296,771 Gain (loss) on early extinguishment of debt — 5,403 Equity income, net – related parties 85,788 112,385 Other income 16,629 31,741 Items impacting comparability Acquisition-related expenses (1) (113,188) — Adjusted EBITDA attributable to noncontrolling interests 58,141 54,650 Adjusted EBITDA (2) $ 2,480,782 $ 2,344,038 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Interest (income) expense, net 390,490 378,513 Accretion and amortization of long-term obligations, net (6,945) (9,238) Current income tax expense (benefit) 11,142 3,900 Other (income) expense, net (16,629) (31,741) Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850 Changes in assets and liabilities: Accounts receivable, net (36,018) 42,798 Accounts and imbalance payables and accrued liabilities, net 3,969 21,935 Other items, net (174,290) (175,189) Acquisition-related expenses (1) 113,188 — Adjusted EBITDA attributable to noncontrolling interests (58,141) (54,650) Adjusted EBITDA (2) $ 2,480,782 $ 2,344,038 Cash flow information Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Net cash used in investing activities (1,085,206) (39,168) Net cash used in financing activities (1,408,392) (1,280,015) _________________________________________________________________________________________ (1) Acquisition-related expenses include (i) $97.3 million of severance costs and (ii) $15.9 million of third-party consulting and legal fees. Non-cash equity-based compensation expense for the year ended December 31, 2025, includes $7.3 million in acquisition-related severance costs. (2) Includes non-cash revenue of $(14.0) million and $39.7 million for the years ended December 31, 2025 and 2024, respectively. 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. 64 Table of Contents Year Ended December 31, thousands 2025 2024 Reconciliation of Net cash provided by operating activities to Free Cash Flow Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Less: Capital expenditures 727,991 833,856 Contributions to equity investments (including capitalized interest) — 9,690 Add: Distributions from equity investments in excess of cumulative earnings — related parties 31,391 30,850 Free Cash Flow $ 1,526,025 $ 1,324,164 Cash flow information Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Net cash used in investing activities (1,085,206) (39,168) Net cash used in financing activities (1,408,392) (1,280,015) 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 Revenue s, Cost of Product (Natural-gas purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense). Gross margin increased by $143.1 million for the year ended December 31, 2025, primarily due to a $238.2 million increase in total revenues and other, partially offset by a $60.4 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 $398.8 million for the year ended December 31, 2025, primarily due to (i) a $307.9 million decrease in gain (loss) on divestiture and other, net and (ii) a $273.0 million increase in total operating expenses. These amounts were offset partially by a $238.2 million increase in total revenues and other. Net cash provided by operating activities. Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods. 65 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2025 2024 Inc/(Dec) Adjusted Gross Margin $ 3,549,557 $ 3,376,793 5 % Per - Mcf Adjusted Gross Margin for natural - gas assets (1) 1.30 1.30 — % Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (1) 3.01 2.94 2 % Per - Bbl Adjusted Gross Margin for produced - water assets (1) 0.89 0.96 (7) % Adjusted EBITDA 2,480,782 2,344,038 6 % Free Cash Flow 1,526,025 1,324,164 15 % _________________________________________________________________________________________ (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 $172.8 million for the year ended December 31, 2025, primarily due to (i) the acquisition of Aris and increased throughput at the DBM water systems and (ii) increased throughput at the West Texas complex and DBM oil system. These increases were offset partially by (i) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024 and decreased throughput at the Springfield gas-gathering system, (ii) the sale of our interests in the Marcellus Interest systems, Saddlehorn, and Mont Belvieu JV during 2024, (iii) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput at the DJ Basin oil system, and (iv) decreased throughput at the Granger complex. Per - Mcf Adjusted gross margin for natural - gas assets was unchanged for the year ended December 31, 2025, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, offset by lower average prices at the DJ Basin complex. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.07 for the year ended December 31, 2025, primarily due to (i) increased throughput at the DBM oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) lower throughput at TEP and FRP, which have lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (iii) the sale of our interest in Whitethorn LLC which had a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets. These increases were offset partially by decreased revenues associated with lower annual cumulative catch-up adjustments for cost-of-service changes at the DJ Basin oil and Springfield oil-gathering systems that increased revenues in the fourth quarter of 2024 and decreased revenues in the fourth quarter of 2025. Per - Bbl Adjusted Gross Margin for produced - water assets decreased by $0.07 for the year ended December 31, 2025, primarily due to the acquisition of Aris. Adjusted EBITDA. Adjusted EBITDA increased by $136.7 million for the year ended December 31, 2025, primarily due to a $238.2 million increase in total revenues and other. This amount was offset partially by (i) a $35.3 million increase in operation and maintenance expenses, (ii) a $34.7 million increase in cost of product (net of lower of cost or market inventory adjustments), (iii) a $19.9 million decrease in distributions from equity investments, and (iv) a $6.7 million increase in property taxes. Free Cash Flow. Free Cash Flow increased by $201.9 million for the year ended December 31, 2025, primarily due to (i) a $105.9 million decrease in capital expenditures, (ii) an $85.8 million increase in net cash provided by operating activities, and (iii) a $9.7 million decrease in contributions to equity investments. 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. 66 Table of Contents 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. The New York Mercantile Exchange West Texas Intermediate crude - oil daily settlement prices during 2024 ranged from a low of $65.75 per barrel in September 2024 to a high of $86.91 per barrel in April 2024, and prices during the year ended December 31, 2025, ranged from a low of $ 55.27 per barrel in December 2025 to a high o f $80.04 per barrel in January 2025. The Waha Hub natural-gas prices during 2024 ranged from a low of ($6.23) per MMBtu in August 2024 to a high of $8.27 per MMBtu in January 2024, and prices during the year ended December 31, 2025, ranged from a low of ($8.82) per MMBtu in October 2025 to a high of $ 7.50 per MMBtu in January 2025. 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 in favorable commodity-price environments, our customers face operational challenges such as severe weather disruptions, oil and gas takeaway constraints, produced water recycling and disposal limitations, seismicity concerns, new regulatory requirements, and optimizing large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can significantly impact 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. For examples of proposed regulations or other regulatory initiatives that could have a potentially material impact on us, see the Environmental Matters and Occupational Health and Safety Regulations section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K. Impact of inflation and tariffs. High inflation in the U.S. has raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, raising operating costs and capital expenditures. Additionally, the Trump administration has imposed significant import tariffs, including on imports of steel and aluminum, and may impose further tariffs on other U.S. trading partners. These tariffs could substantially increase our operating and capital costs. While future inflation and tariff impacts are uncertain, higher operating and capital costs could materially and negatively affect 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. 67 Table of Contents Impact of interest rates. Interest rates can be volatile, affecting our interest expense on RCF and commercial paper borrowings. Future increased interest rates would likely 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 may affect investor yield requirements. A rising interest-rate environment could have an adverse impact on our unit price and ability to issue equity to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our peers face similar interest-rate dynamics. LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, acquisitions, and capital expenditures. Our sources of liquidity, as of December 31, 2025, included cash and cash equivalents, cash flows generated from operations, effective 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. We distribute all our available cash, as defined in our partnership agreement, within 55 days following each quarter’s end. The Board declared a cash distribution to unitholders for the fourth quarter of 2025 of $0.910 per unit, or $379.7 million in the aggregate. The cash distribution was paid on February 13, 2026, to our unitholders of record at the close of business on February 2, 2026. In February 2025, the Board authorized a buyback program of up to $250.0 million of our common units through December 31, 2026 (the “2025 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. 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 acquire any common units, and the program may be suspended or discontinued at our discretion without prior notice. For the year ended December 31, 2026, capital expenditures are expected to range between $850.0 million to $1.0 billion (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Management continuously monitors our leverage position and 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, 2025, we had a $420.5 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. The effective borrowing capacity under the RCF was $2.0 billion as of December 31, 2025. Any outstanding commercial paper borrowings reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its commercial paper program. See Note 11—Selected Components of Working Capital and Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 68 Table of Contents 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 (i) maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, or to remain in compliance with regulatory or legal requirements, and (ii) 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, thousands 2025 2024 Acquisitions $ 368,638 $ 443 Capital expenditures (1) 727,991 833,856 Capital incurred (1) 739,454 798,330 _________________________________________________________________________________________ (1) For the years ended December 31, 2025 and 2024, included $10.2 million and $15.2 million, respectively, of capitalized interest. Acquisitions for the year ended December 31, 2025, included the acquisition of Aris. See Items Affecting the Comparability of Our Financial Results within this Item 7. Capital expenditures decreased by $105.9 million for the year ended December 31, 2025, primarily due to decreases of (i) $216.8 million at the West Texas complex, primarily attributable to construction costs incurred in 2024 associated with the North Loving plant that was completed in the first quarter of 2025 and (ii) $23.3 million at the DBM water systems due to decreased construction of certain water - disposal wells, equipment, facilities, and well-connect projects. These decreases were offset partially by increases of (i) $63.5 million at the Powder River Basin complex primarily attributable to an increase in construction of facilities and well-connect projects and (ii) $25.5 million at the DBM oil system related to an increase in pipeline, oil pumping, and electrical distribution projects. 69 Table of Contents 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, thousands 2025 2024 Net cash provided by (used in): Operating activities $ 2,222,625 $ 2,136,860 Investing activities (1,085,206) (39,168) Financing activities (1,408,392) (1,280,015) Net increase (decrease) in cash and cash equivalents $ (270,973) $ 817,677 Operating activities . Net cash provided by operating activities increased for the year ended December 31, 2025, primarily due to the impact of changes in assets and liabilities, including cash received on certain contracts for which revenue recognition is deferred (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) and higher cash operating income. These increases were offset partially by lower distributions from equity-investment earnings and higher interest expense. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities . Net cash used in investing activities for the year ended December 31, 2025, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, Powder River Basin complex, DJ Basin complex, DBM oil system, Chipeta complex, and DJ Basin oil system, (ii) cash paid, net of cash received for the acquisition of Aris, and (iii) distributions received from equity investments in excess of cumulative earnings. Net cash used in investing activities for the year ended December 31, 2024, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, Powder River Basin complex, and DBM oil system, (ii) increases to materials and supplies inventory and other, (iii) proceeds related to the sale of several equity investments to third parties, (iv) proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party, and (v) distributions received from equity investments in excess of cumulative earnings. Financing activities . Net cash used in financing activities for the year ended December 31, 2025, primarily included (i) distributions paid to WES unitholders and noncontrolling interest owners, (ii) repayment of the total principal amount outstanding of the 3.950% Senior Notes due 2025 and 3.100% Senior Notes due 2025 at par value, and (iii) proceeds from the 5.500% Senior Notes due 2035 and 4.800% Senior Notes due 2031 issued in December 2025. Net cash used in financing activities for the year ended December 31, 2024, primarily included (i) distributions paid to WES unitholders and noncontrolling interest owners, (ii) net repayments under the commercial paper program, (iii) retiring portions of certain of WES Operating’s senior notes via open-market repurchases, and (iv) proceeds from the 5.450% Senior Notes due 2034 issued in August 2024. 70 Table of Contents Debt and credit facilities. As of December 31, 2025, (i) the carrying value of outstanding debt was $8.6 billion, (ii) the estimated future interest and RCF fee payments total $459.8 million in 2026, (iii) the 4.650% Senior Notes due 2026 are classified as short-term debt on the consolidated balance sheet, and (iv) the effective borrowing capacity under WES Operating’s $2.0 billion RCF is $2.0 billion. Any outstanding commercial paper borrowings reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its commercial paper program. During the year ended December 31, 2025, WES Operating (i) completed the public offerings of $600.0 million in aggregate principal amount of 4.800% Senior Notes due 2031 and $600.0 million in aggregate principal amount of 5.500% Senior Notes due 2035, (ii) assumed $500.0 million in aggregate principal amount of 7.250% Senior Notes due 2030 in connection with the Aris acquisition (see Acquisitions and Divestitures within Items 1 and 2 of this Form 10-K ) , (iii) retired the 3.950% Senior Notes due 2025 on the maturity date of June 1, 2025, for $336.8 million, and (iv) retired the 3.100% Senior Notes due 2025 on the maturity date of February 3, 2025, for $663.8 million. WES Operating repaid the 3.950% Senior Notes due 2025 and 3.100% Senior Notes due 2025 with cash on hand, including proceeds received from the 2024 public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034. For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Finance leases. We have finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming. As of December 31, 2025, we have future finance-lease payments of $8.8 million in 2026, and a total of $14.1 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in 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, 2025, we expect to incur asset retirement costs of $9.9 million in 2026, and a total of $427.9 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 operating leases for equipment supporting our operations, corporate offices, field offices, and easements, with both Occidental and third parties as lessors. As of December 31, 2025, we have future operating-lease payments of $66.4 million in 2026, and a total of $133.2 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 offload agreements with third parties providing natural-gas firm-processing capacity through 2028 and produced-water disposal capacity through 2036. As of December 31, 2025, we have future minimum payments under offload agreements totaling $19.6 million for 2026, and a total of $312.8 million in years thereafter. Pipeline commitments. We have transportation contracts with volume commitments on multiple pipelines through 2038. As of December 31, 2025, we have estimated future minimum-volume-commitment fees totaling $4.8 million in 2026, and a total of $263.1 million in years thereafter. 71 Table of Contents Credit risk . We bear credit risk through exposure to non - payment or non - performance by our counterparties (e.g., Occidental and other customers, financial institutions, and other parties), including risks 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. 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, thousands 2025 2024 2023 Net income (loss) attributable to WES $ 1,180,983 $ 1,573,571 $ 1,022,216 Limited partner interest in WES Operating not held by WES (1) 23,835 32,156 20,922 General and administrative expenses (2) 720 1,875 2,943 Other income (expense), net (359) (252) (275) Income taxes 2,734 8 6 Net income (loss) attributable to WES Operating $ 1,207,913 $ 1,607,358 $ 1,045,812 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. 72 Table of Contents 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, thousands 2025 2024 2023 WES net cash provided by operating activities $ 2,222,625 $ 2,136,860 $ 1,661,334 General and administrative expenses (1) 720 1,875 2,943 Non - cash equity - based compensation expense (608) (581) (581) Changes in working capital (29,656) (29,198) (15,226) Other income (expense), net (359) (252) (275) Income taxes — 8 6 WES Operating net cash provided by operating activities $ 2,192,722 $ 2,108,712 $ 1,648,201 WES net cash provided by (used in) financing activities $ (1,408,392) $ (1,280,015) $ (67,912) Distributions to WES unitholders (2) 1,431,024 1,246,069 978,430 Distributions to WES from WES Operating (3) (1,435,970) (1,246,702) (1,119,367) Increase (decrease) in outstanding checks 2,411 50 (52) Unit repurchases — — 134,602 Other 27,337 27,316 15,472 WES Operating net cash provided by (used in) financing activities $ (1,383,590) $ (1,253,282) $ (58,827) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. (2) Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (3) Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta. WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders according to the terms of its limited partnership agreement. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 73 Table of Contents 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 historical 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. Impairments of equity investments. Management assesses its equity investments for impairment when 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 $14.8 million and $6.2 million for the years ended December 31, 2025 and 2024, respectively. See Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the periods presented. 74 Table of Contents 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 and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 75 Table of Contents 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, 2025, and excluding the impact of equity investments, 97% of our wellhead natural - gas volume and 100% of our crude - oil and produced - water throughput 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 Comm ittee lowered its target range for the federal funds rate three times in 202 4 and decreased it twice during the year ended December 31, 2025. Any future increases in the federal funds rate likely will result in an increase in financing costs. As of December 31, 2025, 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) no 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, 2025, 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. 76 Table of Contents Item 8. Financial Statements INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Management’s Assessment of Internal Control Over Financial Reporting 78 Western Midstream Partners, LP 79 Reports of Independent Registered Public Accounting Firm 79 Financial Statements 83 Consolidated Statements of Operations for the years ended December 31, 202 5 , 202 4 , and 202 3 83 Consolidated Balance Sheets as of December 31, 202 5 and 202 4 84 Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 202 5 , 202 4 , and 202 3 85 Consolidated Statements of Cash Flows for the years ended December 31, 202 5 , 202 4 , and 202 3 86 Western Midstream Operating, LP 87 Report of Independent Registered Public Accounting Firm 87 Financial Statements 89 Consolidated Statements of Operations for the years ended December 31, 202 5 , 202 4 , and 20 23 89 Consolidated Balance Sheets as of December 31, 202 5 and 202 4 90 Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 202 5 , 202 4 , and 202 3 91 Consolidated Statements of Cash Flows for the years ended December 31, 202 5 , 202 4 , and 202 3 92 Notes to Consolidated Financial Statements 93 Note 1. Summary of Significant Accounting Policies and Basis of Presentation 93 Note 2. Revenue from Contracts with Customers 102 Note 3. Acquisitions and Divestitures 104 Note 4. Partnership Distributions 107 Note 5. Equity and Partners’ Capital 109 Note 6. Related-Party Transactions 110 Note 7. Equity Investments 113 Note 8. Income Taxes 116 Note 9. Property, Plant, and Equipment 118 Note 10. Goodwill and Other Intangibles 119 Note 11. Selected Components of Working Capital 120 Note 12. Asset Retirement Obligations 121 Note 13. Debt and Interest Expense 122 Note 14. Leases 125 Note 15. Equity-Based Compensation 127 Note 16. Commitments and Contingencies 129 Note 17. Reportable Segment 130 Note 1 8 . Subsequent Event 132 77 Table of Contents 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, 2025. 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, 2025. The Partnership acquired Aris Water Solutions, Inc. during 2025 and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2025, Aris Water Solutions, Inc.’s internal control over financial reporting associated with total assets of $2.3 billion and total revenues of $116.4 million included in the consolidated financial statements of Western Midstream Partners, LP and subsidiaries as of and for the year ended December 31, 2025. 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, 2025. WESTERN MIDSTREAM PARTNERS, LP /s/ Oscar K. Brown Oscar K. Brown 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/ Oscar K. Brown Oscar K. Brown 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 18, 2026 78 Table of Contents 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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, 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, 2025, 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 18, 2026 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. 79 Table of Contents 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 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 18, 2026 80 Table of Contents 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, 2025, 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, 2025, 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, 2025 and 2024, 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, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 18, 2026 expressed an unqualified opinion on those consolidated financial statements. The Partnership acquired Aris Water Solutions, Inc. during 2025, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2025, Aris Water Solutions, Inc.’s internal control over financial reporting associated with total assets of $2.3 billion and total revenues of $116.4 million included in the consolidated financial statements of the Partnership as of and for the year ended December 31, 2025. Our audit of internal control over financial reporting of the Partnership also excluded an evaluation of the internal control over financial reporting of Aris Water Solutions, Inc. 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. 81 Table of Contents 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 18, 2026 82 Table of Contents WESTERN MIDSTREAM PARTNERS, LP CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, thousands except per-unit amounts 2025 2024 2023 Revenues and other Service revenues – fee based $ 3,453,052 $ 3,248,262 $ 2,768,757 Service revenues – product based 193,866 215,776 191,727 Product sales 194,681 140,100 145,024 Other 1,804 1,085 968 Total revenues and other (1) 3,843,403 3,605,223 3,106,476 Equity income, net – related parties 85,788 112,385 152,959 Operating expenses Cost of product 206,978 172,251 164,598 Operation and maintenance 915,896 880,568 762,530 General and administrative 398,922 271,526 232,632 Property and other taxes 69,342 62,668 56,458 Depreciation and amortization 710,778 650,428 600,668 Long - lived asset and other impairments 14,760 6,206 52,884 Total operating expenses (2) 2,316,676 2,043,647 1,869,770 Gain (loss) on divestiture and other, net ( 11,113 ) 296,771 ( 10,102 ) Operating income (loss) 1,601,402 1,970,732 1,379,563 Interest expense ( 390,490 ) ( 378,513 ) ( 348,228 ) Gain (loss) on early extinguishment of debt — 5,403 15,378 Other income (expense), net 16,629 31,741 5,679 Income (loss) before income taxes 1,227,541 1,629,363 1,052,392 Income tax expense (benefit) 15,086 18,111 4,385 Net income (loss) 1,212,455 1,611,252 1,048,007 Net income (loss) attributable to noncontrolling interests 31,472 37,681 25,791 Net income (loss) attributable to Western Midstream Partners, LP $ 1,180,983 $ 1,573,571 $ 1,022,216 Limited partners’ interest in net income (loss): Net income (loss) attributable to Western Midstream Partners, LP $ 1,180,983 $ 1,573,571 $ 1,022,216 General partner interest in net (income) loss ( 26,485 ) ( 36,604 ) ( 23,684 ) Limited partners’ interest in net income (loss) (3) 1,154,498 1,536,967 998,532 Net income (loss) per common unit – basic (3) $ 2.99 $ 4.04 $ 2.61 Net income (loss) per common unit – diluted (3) $ 2.98 $ 4.02 $ 2.60 Weighted - average common units outstanding – basic (3) 386,074 380,397 383,028 Weighted - average common units outstanding – diluted (3) 387,880 382,455 384,408 _________________________________________________________________________________________ (1) Total revenues and other includes related - party amounts of $ 2.3 billion, $ 2.2 billion, and $ 1.8 billion for the years ended December 31, 2025, 2024, and 2023, respectively. See Note 6 . (2) Total operating expenses includes related - party amounts of $ 12.1 million, $( 56.5 ) million, and $( 68.0 ) million for the years ended December 31, 2025, 2024, and 2023, respectively, all primarily related to changes in imbalance positions. See Note 6 . (3) See Note 5. See accompanying Notes to Consolidated Financial Statements. 83 Table of Contents WESTERN MIDSTREAM PARTNERS, LP CONSOLIDATED BALANCE SHEETS December 31, thousands except number of units 2025 2024 ASSETS Current assets Cash and cash equivalents $ 819,491 $ 1,090,464 Accounts receivable, net 773,197 701,838 Other current assets 64,253 54,888 Total current assets 1,656,941 1,847,190 Property, plant, and equipment Cost 17,648,375 15,509,910 Less accumulated depreciation 6,427,467 5,795,301 Net property, plant, and equipment 11,220,908 9,714,609 Goodwill 353,257 4,783 Other intangible assets 913,758 649,740 Equity investments 504,859 541,435 Other assets 348,697 387,028 Total assets (1) $ 14,998,420 $ 13,144,785 LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL Current liabilities Accounts and imbalance payables $ 319,170 $ 312,945 Short - term debt 448,825 1,011,032 Accrued ad valorem taxes 60,114 38,319 Accrued liabilities 408,375 329,398 Total current liabilities 1,236,484 1,691,694 Long-term liabilities Long - term debt 8,195,170 6,926,647 Deferred income taxes 111,277 29,679 Asset retirement obligations 427,858 370,195 Other liabilities 864,509 751,400 Total long - term liabilities 9,598,814 8,077,921 Total liabilities (2) 10,835,298 9,769,615 Equity and partners’ capital Common units ( 408,141,366 and 380,556,643 units issued and outstanding at December 31, 2025 and 2024, respectively) 4,016,606 3,224,802 General partner units ( 9,060,641 units issued and outstanding at December 31, 2025 and 2024) 4,624 10,803 Total partners’ capital 4,021,230 3,235,605 Noncontrolling interests 141,892 139,565 Total equity and partners’ capital 4,163,122 3,375,170 Total liabilities, equity, and partners’ capital $ 14,998,420 $ 13,144,785 ________________________________________________________________________________________ (1) Total assets includes related - party amounts of $ 946.4 million and $ 991.1 million as of December 31, 2025 and 2024, respectively, which includes related - party Accounts receivable, net of $ 407.9 million and $ 401.3 million as of December 31, 2025 and 2024, respectively. See Note 6 . (2) Total liabilities includes related - party amounts of $ 666.9 million and $ 529.7 million as of December 31, 2025 and 2024, respectively, which includes related-party Accounts and imbalance payables of $ 20.6 million as of December 31, 2025 and 2024. See Note 6 . See accompanying Notes to Consolidated Financial Statements. 84 Table of Contents WESTERN MIDSTREAM PARTNERS, LP CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL Partners’ Capital thousands Common Units General Partner Units Noncontrolling Interests Total 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 Net income (loss) 1,536,967 36,604 37,681 1,611,252 Distributions to Chipeta noncontrolling interest owner — — ( 4,372 ) ( 4,372 ) Distributions to noncontrolling interest owner of WES Operating — — ( 25,450 ) ( 25,450 ) Distributions to Partnership unitholders ( 1,217,075 ) ( 28,994 ) — ( 1,246,069 ) Equity - based compensation expense 37,994 — — 37,994 Other ( 27,315 ) — — ( 27,315 ) Balance at December 31, 2024 $ 3,224,802 $ 10,803 $ 139,565 $ 3,375,170 Net income (loss) 1,154,498 26,485 31,472 1,212,455 Acquisition-related issuance of units 1,005,017 — — 1,005,017 Distributions to Chipeta noncontrolling interest owner — — ( 2,095 ) ( 2,095 ) Distributions to noncontrolling interest owner of WES Operating — — ( 29,534 ) ( 29,534 ) Distribution to Partnership unitholders ( 1,398,360 ) ( 32,664 ) — ( 1,431,024 ) Equity-based compensation expense 50,803 — — 50,803 Other ( 20,154 ) — 2,484 ( 17,670 ) Balance at December 31, 2025 $ 4,016,606 $ 4,624 $ 141,892 $ 4,163,122 _________________________________________________________________________________________ (1) See Note 5 and Note 6 . See accompanying Notes to Consolidated Financial Statements. 85 Table of Contents WESTERN MIDSTREAM PARTNERS, LP CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, thousands 2025 2024 2023 Cash flows from operating activities Net income (loss) $ 1,212,455 $ 1,611,252 $ 1,048,007 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization 710,778 650,428 600,668 Long - lived asset and other impairments 14,760 6,206 52,884 Non - cash equity - based compensation expense 50,803 37,994 32,005 Deferred income taxes 3,944 14,211 1,044 Accretion and amortization of long - term obligations, net 6,945 9,238 8,151 Equity income, net – related parties ( 85,788 ) ( 112,385 ) ( 152,959 ) Distributions from equity - investment earnings – related parties 90,973 111,386 155,169 (Gain) loss on divestiture and other, net 11,113 ( 296,771 ) 10,102 (Gain) loss on early extinguishment of debt — ( 5,403 ) ( 15,378 ) Other 303 248 442 Changes in assets and liabilities: (Increase) decrease in accounts receivable, net 36,018 ( 42,798 ) ( 78,346 ) Increase (decrease) in accounts and imbalance payables and accrued liabilities, net ( 3,969 ) ( 21,935 ) ( 68,019 ) Change in other items, net 174,290 175,189 67,564 Net cash provided by operating activities 2,222,625 2,136,860 1,661,334 Cash flows from investing activities Capital expenditures ( 727,991 ) ( 833,856 ) ( 735,080 ) Acquisitions from third parties ( 368,638 ) ( 443 ) ( 877,746 ) Contributions to equity investments – related parties — ( 9,690 ) ( 1,153 ) Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850 39,104 Proceeds from the sale of assets to third parties 162 792,255 ( 87 ) (Increase) decrease in materials and supplies inventory and other ( 20,130 ) ( 18,284 ) ( 32,329 ) Net cash used in investing activities ( 1,085,206 ) ( 39,168 ) ( 1,607,291 ) Cash flows from financing activities Borrowings, net of debt issuance costs 1,184,288 789,044 2,448,733 Repayments of debt ( 1,080,589 ) ( 143,852 ) ( 1,967,928 ) Commercial paper borrowings (repayments), net — ( 610,313 ) 609,916 Increase (decrease) in outstanding checks ( 7,973 ) ( 5,622 ) 3,516 Distributions to Partnership unitholders (1) ( 1,431,024 ) ( 1,246,069 ) ( 978,430 ) Distributions to Chipeta noncontrolling interest owner ( 2,095 ) ( 4,372 ) ( 7,641 ) Distributions to noncontrolling interest owner of WES Operating ( 29,534 ) ( 25,450 ) ( 22,850 ) Unit repurchases — — ( 134,602 ) Other ( 41,465 ) ( 33,381 ) ( 18,626 ) Net cash used in financing activities ( 1,408,392 ) ( 1,280,015 ) ( 67,912 ) Net increase (decrease) in cash and cash equivalents ( 270,973 ) 817,677 ( 13,869 ) Cash and cash equivalents at beginning of period 1,090,464 272,787 286,656 Cash and cash equivalents at end of period $ 819,491 $ 1,090,464 $ 272,787 Supplemental disclosures Interest paid, net of capitalized interest $ 380,978 $ 360,847 $ 326,948 Accrued capital expenditures 79,710 64,084 99,610 Income taxes paid (reimbursements received) 3,107 2,225 4,131 Acquisition-related issuance of common units 1,005,017 — — Asset retirement cost additions and revisions, net 40,602 9,738 58,668 _________________________________________________________________________________________ (1) Includes related-party amounts. See Note 6 . See accompanying Notes to Consolidated Financial Statements. 86 Table of Contents 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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, 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. 87 Table of Contents 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 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 18, 2026 88 Table of Contents WESTERN MIDSTREAM OPERATING, LP CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, thousands 2025 2024 2023 Revenues and other Service revenues – fee based $ 3,453,052 $ 3,248,262 $ 2,768,757 Service revenues – product based 193,866 215,776 191,727 Product sales 194,681 140,100 145,024 Other 1,804 1,085 968 Total revenues and other (1) 3,843,403 3,605,223 3,106,476 Equity income, net – related parties 85,788 112,385 152,959 Operating expenses Cost of product 206,978 172,251 164,598 Operation and maintenance 915,896 880,568 762,530 General and administrative 398,202 269,651 229,689 Property and other taxes 69,342 62,668 56,458 Depreciation and amortization 710,778 650,428 600,668 Long-lived asset and other impairments 14,760 6,206 52,884 Total operating expenses (2) 2,315,956 2,041,772 1,866,827 Gain (loss) on divestiture and other, net ( 11,113 ) 296,771 ( 10,102 ) Operating income (loss) 1,602,122 1,972,607 1,382,506 Interest expense ( 390,490 ) ( 378,513 ) ( 348,228 ) Gain (loss) on early extinguishment of debt — 5,403 15,378 Other income (expense), net 16,270 31,489 5,404 Income (loss) before income taxes 1,227,902 1,630,986 1,055,060 Income tax expense (benefit) 12,352 18,103 4,379 Net income (loss) 1,215,550 1,612,883 1,050,681 Net income (loss) attributable to noncontrolling interest 7,637 5,525 4,869 Net income (loss) attributable to Western Midstream Operating, LP $ 1,207,913 $ 1,607,358 $ 1,045,812 ________________________________________________________________________________________ (1) Total revenues and other includes related - party amounts of $ 2.3 billion, $ 2.2 billion, and $ 1.8 billion for the years ended December 31, 2025, 2024, and 2023, respectively. See Note 6 . (2) Total operating expenses includes related - party amounts of $ 16.3 million, $( 52.7 ) million, and $( 64.7 ) million for the years ended December 31, 2025, 2024, and 2023, respectively, all primarily related to changes in imbalance positions. See Note 6 . See accompanying Notes to Consolidated Financial Statements. 89 Table of Contents WESTERN MIDSTREAM OPERATING, LP CONSOLIDATED BALANCE SHEETS December 31, thousands except number of units 2025 2024 ASSETS Current assets Cash and cash equivalents $ 808,372 $ 1,084,446 Accounts receivable, net 773,165 701,814 Other current assets 63,604 53,775 Total current assets 1,645,141 1,840,035 Property, plant, and equipment Cost 17,648,375 15,509,910 Less accumulated depreciation 6,427,467 5,795,301 Net property, plant, and equipment 11,220,908 9,714,609 Goodwill 353,257 4,783 Other intangible assets 913,758 649,740 Equity investments 504,859 541,435 Other assets 345,529 383,808 Total assets (1) $ 14,983,452 $ 13,134,410 LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL Current liabilities Accounts and imbalance payables $ 376,947 $ 339,108 Short - term debt 448,825 1,011,032 Accrued ad valorem taxes 60,114 38,319 Accrued liabilities 326,873 248,589 Total current liabilities 1,212,759 1,637,048 Long-term liabilities Long - term debt 8,195,170 6,926,647 Deferred income taxes 36,646 29,679 Asset retirement obligations 427,858 370,195 Other liabilities 859,947 744,715 Total long - term liabilities 9,519,621 8,071,236 Total liabilities (2) 10,732,380 9,708,284 Equity and partners’ capital Common units ( 403,205,667 and 318,675,578 units issued and outstanding at December 31, 2025 and 2024, respectively) 3,347,576 3,399,650 Preferred units ( 21,965,846 and zero units issued and outstanding at December 31, 2025 and 2024, respectively) 868,978 — Total partners’ capital 4,216,554 3,399,650 Noncontrolling interest 34,518 26,476 Total equity and partners’ capital 4,251,072 3,426,126 Total liabilities, equity, and partners’ capital $ 14,983,452 $ 13,134,410 _________________________________________________________________________________________ (1) Total assets includes related - party amounts of $ 943.2 million and $ 987.4 million as of December 31, 2025 and 2024, respectively, which includes related - party Accounts receivable, net of $ 407.9 million and $ 401.3 million as of December 31, 2025 and 2024, respectively. See Note 6 . (2) Total liabilities includes related - party amounts of $ 722.3 million and $ 555.9 million as of December 31, 2025 and 2024, respectively, which includes related-party Accounts and imbalance payables of $ 76.0 million and $ 46.8 million as of December 31, 2025 and 2024, respectively. See Note 6 . See accompanying Notes to Consolidated Financial Statements. 90 Table of Contents WESTERN MIDSTREAM OPERATING, LP CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL thousands Common Units Preferred Units Noncontrolling Interests Total 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 Net income (loss) 1,607,358 — 5,525 1,612,883 Distributions to Chipeta noncontrolling interest owner — — ( 4,372 ) ( 4,372 ) Distributions to WES Operating unitholders ( 1,272,152 ) — — ( 1,272,152 ) Contributions of equity-based compensation from WES 37,413 — — 37,413 Balance at December 31, 2024 $ 3,399,650 $ — $ 26,476 $ 3,426,126 Net income (loss) 1,192,967 14,946 7,637 1,215,550 Acquisition-related issuance of units 170,268 854,032 — 1,024,300 Distributions to Chipeta noncontrolling interest owner — — ( 2,095 ) ( 2,095 ) Distributions to WES Operating unitholders ( 1,465,504 ) — — ( 1,465,504 ) Contributions of equity-based compensation from WES 50,195 — — 50,195 Other — — 2,500 2,500 Balance at December 31, 2025 $ 3,347,576 $ 868,978 $ 34,518 $ 4,251,072 See accompanying Notes to Consolidated Financial Statements. 91 Table of Contents WESTERN MIDSTREAM OPERATING, LP CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, thousands 2025 2024 2023 Cash flows from operating activities Net income (loss) $ 1,215,550 $ 1,612,883 $ 1,050,681 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization 710,778 650,428 600,668 Long-lived asset and other impairments 14,760 6,206 52,884 Non-cash equity-based compensation expense 50,195 37,413 31,424 Deferred income taxes 1,210 14,211 1,044 Accretion and amortization of long-term obligations, net 6,945 9,238 8,151 Equity income, net – related parties ( 85,788 ) ( 112,385 ) ( 152,959 ) Distributions from equity-investment earnings – related parties 90,973 111,386 155,169 (Gain) loss on divestiture and other, net 11,113 ( 296,771 ) 10,102 (Gain) loss on early extinguishment of debt — ( 5,403 ) ( 15,378 ) Other 303 248 442 Changes in assets and liabilities: (Increase) decrease in accounts receivable, net 36,027 ( 42,796 ) ( 78,324 ) Increase (decrease) in accounts and imbalance payables and accrued liabilities, net ( 35,239 ) ( 47,822 ) ( 83,332 ) Change in other items, net 175,895 171,876 67,629 Net cash provided by operating activities 2,192,722 2,108,712 1,648,201 Cash flows from investing activities Capital expenditures ( 727,991 ) ( 833,856 ) ( 735,080 ) Acquisitions from third parties ( 368,638 ) ( 443 ) ( 877,746 ) Contributions to equity investments – related parties — ( 9,690 ) ( 1,153 ) Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850 39,104 Proceeds from the sale of assets to third parties 162 792,255 ( 87 ) (Increase) decrease in materials and supplies inventory and other ( 20,130 ) ( 18,284 ) ( 32,329 ) Net cash used in investing activities ( 1,085,206 ) ( 39,168 ) ( 1,607,291 ) Cash flows from financing activities Borrowings, net of debt issuance costs 1,184,288 789,044 2,448,733 Repayments of debt ( 1,080,589 ) ( 143,852 ) ( 1,967,928 ) Commercial paper borrowings (repayments), net — ( 610,313 ) 609,916 Increase (decrease) in outstanding checks ( 5,562 ) ( 5,572 ) 3,464 Distributions to WES Operating unitholders (1) ( 1,465,504 ) ( 1,272,152 ) ( 1,142,217 ) Distributions to Chipeta noncontrolling interest owner ( 2,095 ) ( 4,372 ) ( 7,641 ) Other ( 14,128 ) ( 6,065 ) ( 3,154 ) Net cash used in financing activities ( 1,383,590 ) ( 1,253,282 ) ( 58,827 ) Net increase (decrease) in cash and cash equivalents ( 276,074 ) 816,262 ( 17,917 ) Cash and cash equivalents at beginning of period 1,084,446 268,184 286,101 Cash and cash equivalents at end of period $ 808,372 $ 1,084,446 $ 268,184 Supplemental disclosures Interest paid, net of capitalized interest $ 380,978 $ 360,847 $ 326,948 Accrued capital expenditures 79,710 64,084 99,610 Income taxes paid (reimbursements received) 3,107 2,225 4,131 Acquisition-related issuance of common and preferred units 1,024,300 — — Asset retirement cost additions and revisions, net 40,602 9,738 58,668 ________________________________________________________________________________________ (1) Includes related-party amounts. See Note 6. See accompanying Notes to Consolidated Financial Statements. 92 Table of Contents 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 (the “Partnership”) 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. As of December 31, 2025, the Partnership owns, directly and indirectly, a 98.1 % 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. In addition, Occidental owns the Partnership’s general partner and, as of December 31, 2025, a 1.9 % limited partner interest in WES Operating through its ownership of WGR Asset Holding Company LLC (“WGRAH”). See Noncontrolling interests below. 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, which became a wholly owned subsidiary of Occidental as a result of Occidental’s acquisition by merger of Anadarko in 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 WES Operating for transactions with the Partnership that eliminate upon consolidation (see Note 6 ). On October 15, 2025, the Partnership completed its previously announced acquisition of Aris Water Solutions, Inc. (“Aris”), pursuant to the Agreement and Plan of Merger, dated as of August 6, 2025 (the “Merger Agreement”), by and among the Partnership, Aris, and certain Partnership and Aris subsidiaries. Also, immediately following the closing of the Aris acquisition, WES Operating and Aris entered into certain post-closing restructuring transactions through which WES Operating issued preferred units to Aris in exchange for Aris’s operating subsidiaries, and WES Operating was the surviving entity in a merger with Aris Water Holdings, LLC, a subsidiary of Aris that was the issuer of its acquired outstanding senior notes (see Note 3) . 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, transporting, recycling, treating, supplying, and disposing of produced water. In its capacity as a natural - gas processor, the Partnership also buys and sells residue, NGLs, and condensate on behalf of itself and its customers under certain contracts. As of December 31, 2025, the Partnership’s assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems 13 2 1 Treating facilities 43 3 — Processing plants/trains 27 3 1 Produced-water gathering, treating, recycling, and disposal systems 8 — — NGLs pipelines 3 — 4 Natural - gas pipelines 6 — 1 Crude - oil pipelines 2 1 1 These assets and investments are located in Texas, New Mexico, and the Rocky Mountains (Colorado, Utah, and Wyoming). 93 Table of Contents 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 or other financial interest, including WES Operating, WES Operating GP, proportionately consolidated interests, and equity investments. 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 system 50.10 % 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 % Rendezvous Gas Services, LLC (“Rendezvous”) 22.00 % Texas Express Pipeline LLC (“TEP”) 20.00 % Texas Express Gathering LLC (“TEG”) 20.00 % 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 this asset. (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 elimination of the preferred unit investment in WES Operating with the Partnership’s underlying preferred capital account (see Note 5) , (iv) the general and administrative expenses incurred by the Partnership, which are separate from, and in addition to, those incurred by WES Operating, (v) the inclusion of the impact of Partnership equity balances and Partnership distributions, and (vi) transactions between the Partnership and WES Operating that eliminate upon consolidation. 94 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION 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 for all periods presented and (ii) the 1.9 %, 2.0 %, and 2.0 % limited partner interest in WES Operating as of December 31, 2025, 2024, and 2023, respectively, owned by an Occidental subsidiary. WES Operating’s noncontrolling interest in the consolidated financial statements consists of the 25 % third - party interest in Chipeta. 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. 95 Table of Contents 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, 2025, 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, 2025 and 2024. 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, 2025, imbalance receivables and payables were $ 12.2 million and $ 10.8 million, respectively. As of December 31, 2024, imbalance receivables and payables were $ 7.3 million and $ 5.2 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 and is stated at the lower of weighted-average cost or net realizable value. 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. As of December 31, 2025 and 2024, Other current assets includes (i) $ 2.7 million and $ 2.5 million, respectively, of NGLs inventory and (ii) $ 10.1 million and $ 0.6 million, respectively, of materials and supplies inventory that are classified as short term on the consolidated balance sheets. As of December 31, 2025 and 2024, Other assets includes (i) $ 3.2 million and $ 5.5 million, respectively, of NGLs line - fill inventory, and (ii) $ 131.6 million and $ 110.3 million, respectively, of materials and supplies inventory that are classified as long term on the consolidated balance sheets. 96 Table of Contents 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 historical carrying value. 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 periods presented. 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. 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 has 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 . 97 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION 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. 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 customers are recognized as contract assets or contract liabilities and are amortized over the related contract period. 98 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION 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. 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. The Partnership receives aid-in-construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs.) 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. See Note 2 . 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 $ 29.5 million, $ 28.9 million, and $ 24.6 million for the years ended December 31, 2025, 2024, and 2023, respectively. 99 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION Partnership income taxes. The Partnership is structured as a publicly traded limited partnership and, therefore, is generally not subject to federal or most state income taxes. The Partnership operates certain business activities through corporate subsidiaries that are subject to federal, state, and local income taxes. These corporate subsidiaries include Arrakis Holdings, Inc, and Aris Water Solutions, Inc. For federal and most state purposes, the earnings or losses of the Partnership, unless they are attributed to a taxable subsidiary, are reported on the individual tax returns of the partners. The net earnings presented in the Partnership’s consolidated financial statements may differ significantly from the taxable income reported to unitholders. These variations arise from differences in the tax basis versus the financial statement basis of assets and liabilities reported in the Partnership’s consolidated financial statements, as well as the allocation requirements established in the Partnership’s partnership agreement. The Partnership does not have access to information regarding each partner’s individual tax basis in the limited partner interests. As a publicly traded limited partnership, the Partnership must comply with a statutory requirement that its “qualifying income,” as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements, exceeds 90% of total gross income on a calendar year basis. Failure to meet this requirement would result in the Partnership being taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2025, 2024, and 2023, the Partnership’s qualifying income satisfied this statutory threshold. The Partnership and its corporate subsidiaries utilize the asset and liability method to account for income taxes. Deferred income tax assets and liabilities are recognized to reflect temporary differences between the financial statement basis and the tax basis of assets and liabilities. These amounts are stated at the enacted tax rates expected to apply when the taxes are paid or recovered. If management determines that it is more likely than not that a deferred tax asset will not be realized, a valuation allowance is established. Any changes in tax legislation are incorporated into the relevant computations during the period in which such changes take effect. The Partnership reviews contingent tax liabilities and estimated exposures using a “more likely than not” standard based on its current tax positions. Consistent with Financial Accounting Standards Board (“FASB”) guidance regarding uncertainty in income taxes, the Partnership may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by tax authorities. This assessment is based on the technical merits of each tax position, as well as the past administrative practices and precedents of the taxing authority. As of December 31, 2025 and 2024, the Partnership had no material uncertain tax positions. See Note 8 . WES Operating income taxes. WES Operating is a limited partnership, generally exempt from federal or state income taxes except for Texas margin tax on Texas-apportioned income. Until August 2024, WES Operating participated in Occidental’s Texas Franchise Tax filings. Deferred state income tax assets and liabilities are recognized for temporary differences and measured at enacted tax rates. A valuation allowance is set up if deferred tax assets are not likely to be realized. Tax legislation changes are reflected as they take effect. Contingent tax liabilities are assessed using a “more likely than not” threshold. Pursuant to FASB guidance, WES Operating only recognizes uncertain tax positions if it is more likely than not they will be upheld by authorities. As of December 31, 2025 and 2024, there were no material uncertain tax positions. See Note 8 . 100 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION 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. 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 began 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) . 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, transport, recycle, treat, supply and dispose of produced water in the United States. Accounting Standards Update 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” was adopted on December 31, 2024, using a retrospective approach with no impact to the consolidated financial statements; however, the adoption did result in additional disclosure. See Note 17 . New accounting pronouncements not yet adopted. In November 2024, the Financial Accounting Standards Board issued Accounting Standards Update 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation (Subtopic 220-40): Disaggregation of Income Statement Expenses.” The standard requires additional disclosure and disaggregation of certain income statement expense line items and may be applied prospectively or retrospectively. The Partnership plans to adopt the standard when it becomes effective beginning with the fiscal-year 2027 annual financial statements. The Partnership is assessing the impact of this guidance on its disclosures in the Notes to the Consolidated Financial Statements. 101 Table of Contents 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, thousands 2025 2024 2023 Revenue from customers Service revenues – fee based $ 3,453,052 $ 3,248,262 $ 2,768,757 Service revenues – product based 193,866 215,776 191,727 Product sales 194,681 140,100 145,024 Total revenue from customers 3,841,599 3,604,138 3,105,508 Revenue from other than customers Other 1,804 1,085 968 Total revenues and other $ 3,843,403 $ 3,605,223 $ 3,106,476 Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets, were $ 737.0 million and $ 693.9 million as of December 31, 2025 and 2024, 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, thousands 2025 2024 Contract assets balance at beginning of year $ 43,186 $ 39,292 Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period ( 14,055 ) ( 7,479 ) Additional estimated revenues recognized 8,117 3,195 Cumulative catch-up adjustment for change in estimated consideration ( 26,733 ) 8,178 Contract assets balance at end of year $ 10,515 $ 43,186 December 31, thousands 2025 2024 Other current assets $ 3,386 $ 12,358 Other assets 7,129 30,828 Total contract assets from contracts with customers $ 10,515 $ 43,186 102 Table of Contents 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, thousands 2025 2024 Contract liabilities balance at beginning of year $ 610,571 $ 445,499 Cash received or receivable, excluding revenues recognized during the period 161,213 193,360 Revenues recognized that were included in the contract liability balance at the beginning of the period ( 4,676 ) ( 28,288 ) Cumulative catch-up adjustment for change in estimated consideration 40 — Contract liabilities balance at end of year $ 767,148 $ 610,571 December 31, thousands 2025 2024 Accrued liabilities $ 22,883 $ 11,055 Other liabilities 744,265 599,516 Total contract liabilities from contracts with customers $ 767,148 $ 610,571 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, 2025, are presented in the table below. 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. See Note 18. thousands 2026 $ 1,110,784 2027 1,167,371 2028 1,007,267 2029 697,968 2030 552,690 Thereafter 2,058,156 Total $ 6,594,236 103 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. ACQUISITIONS AND DIVESTITURES Aris. On October 15, 2025, the Partnership closed on the acquisition of Aris by merger in a transaction valued at $ 2.0 billion, including the cash and equity merger consideration, Aris’s outstanding debt of $ 80.0 million in revolving credit facility borrowings that were repaid at closing, and $ 500.0 million in principal amount of senior notes (see Note 13 ). Based on Aris shareholder consideration elections, the Partnership issued 26.6 million common units and paid $ 415.0 million in cash, funded with borrowings under the commercial paper program, in exchange for all issued and outstanding shares of Aris common stock. The $ 368.6 million included as Acquisitions from third parties in the consolidated statements of cash flows includes the cash paid to Aris shareholders net of cash acquired (as presented in the table below). The Partnership acquired Aris to expand its existing produced-water infrastructure and access additional customers in the area. The assets acquired, located in Lea and Eddy Counties, New Mexico and West Texas, include approximately 830 miles of produced-water pipeline, 1,812 MBbls/d of produced-water handling capacity, 1,560 MBbls/d of water recycling capacity, and 625,000 dedicated acres. The Aris acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Aris acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Aris acquisition were included in the Partnership’s consolidated statements of operations beginning on the acquisition date in the fourth quarter of 2025. For the year ended December 31, 2025, General and administrative expenses in the consolidated statements of operations include acquisition-related transaction costs consisting primarily of $ 104.6 million of severance costs and $ 15.9 million of third-party consulting and legal fees. The following is the preliminary acquisition-date fair value as of December 31, 2025, for the assets acquired and liabilities assumed in the Aris 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 values assigned to tangible and identifiable intangible assets. thousands Assets acquired: Cash and cash equivalents $ 46,362 Accounts receivable, net 90,917 Other current assets 4,782 Property, plant, and equipment 1,458,361 Goodwill 348,474 Other intangible assets 298,844 Other assets 17,617 Total assets acquired 2,265,357 Liabilities assumed: Accounts payable and accrued liabilities 9,183 Other current liabilities 153,700 Long-term debt 531,675 Asset retirement obligation 48,076 Other liabilities 95,538 Total liabilities assumed 838,172 Net assets acquired $ 1,427,185 104 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. ACQUISITIONS AND DIVESTITURES Goodwill recognized in the Aris acquisition relates primarily to enhancing and diversifying the Partnership’s water-asset position, as well as delivering operational synergies, including increasing volumes on its existing processing facilities and increasing revenues on its produced-water systems. See Note 10 . Other intangible assets recognized in the Aris acquisition are related to customer contracts. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 19 years, which represents the estimated term over which the customer contracts are expected to contribute to the Partnership’s cash flows. See Note 10 . The acquisition-date fair values are based on an assessment of the fair value of the assets acquired and liabilities assumed in the Aris acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the produced-water disposal and recycling systems and related facilities and equipment are based on market and cost approaches. The following table presents the pro forma condensed financial information of the Partnership as if the Aris acquisition had occurred on January 1, 2024: Year Ended December 31, thousands 2025 2024 Revenues and other $ 4,281,744 $ 4,082,518 Net income (loss) 1,173,942 1,640,204 The following table presents the pro forma condensed financial information of WES Operating (which is included in the Partnership’s pro forma condensed financial information) as if the Aris acquisition had occurred on January 1, 2024: Year Ended December 31, thousands 2025 2024 Revenues and other $ 4,281,744 $ 4,082,518 Net income (loss) 1,177,037 1,641,835 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 Aris 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 Aris acquisition including (i) adjustments of $ 47.3 million and $ 41.9 million for the years ended December 31, 2025 and 2024, respectively, to increase revenues and cost of product to apply the Partnership’s revenue recognition policy related to skim-oil received from the customer as non-cash consideration for services provided under certain contracts, (ii) adjustments of $ 14.0 million and $ 18.7 million for the years ended December 31, 2025 and 2024, respectively, to increase depreciation and amortization expense based on the acquisition-date fair value and estimated useful lives of property, plant, and equipment, and intangible assets, and (iii) adjustments of $ 9.1 million and $ 12.6 million to increase interest expense for the years ended December 31, 2025 and 2024, respectively, related to borrowings under the commercial paper program to finance the cash-funded portion of the Aris acquisition and the acquisition of Aris’s $ 500.0 million in aggregate principal amount of 7.250 % Senior Notes due 2030. 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 Aris acquisition, nor any future acquisition-related expenses. The pro forma information in the table above includes $ 116.4 million of revenues and $ 93.2 million of expenses attributable to the assets acquired as part of the Aris acquisition that are included in the Partnership’s and WES Operating’s consolidated statements of operations for the year ended December 31, 2025. 105 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. ACQUISITIONS AND DIVESTITURES Marcellus Interest systems. During the second quarter of 2024, the Partnership closed on the sale of its 33.75 % interest in the Marcellus Interest systems for proceeds of $ 206.2 million, resulting in a net gain on sale of $ 63.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations. Mont Belvieu JV, Whitethorn LLC, Panola, and Saddlehorn. During the first quarter of 2024, the Partnership closed on the sale of the following equity investments to third parties: (i) the 25.00 % interest in Enterprise EF78 LLC, (ii) the 20.00 % interest in Whitethorn Pipeline Company LLC, (iii) the 15.00 % interest in Panola Pipeline Company, LLC, and (iv) the 20.00 % interest in Saddlehorn Pipeline Company, LLC. The combined proceeds received in the first quarter of 2024 of $ 588.6 million includes $ 5.9 million in pro-rata distributions through closing, resulting in a net gain on sale of $ 239.7 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations. 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 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), was $ 878.2 million. The following is the final acquisition-date fair value for the assets acquired and liabilities assumed in the Meritage acquisition on October 13, 2023. thousands Assets acquired: Cash and cash equivalents $ 38,412 Accounts receivable, net 34,060 Other current assets 1,980 Property, plant, and equipment 926,347 Other assets 6,498 Total assets acquired 1,007,297 Liabilities assumed: Accounts payable and accrued liabilities 34,733 Other current liabilities 5,451 Asset retirement obligation 22,156 Other liabilities 28,356 Total liabilities assumed 90,696 Net assets acquired $ 916,601 The acquisition-date fair values were 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. 106 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. PARTNERSHIP DISTRIBUTIONS Partnership distributions. The Partnership distributes all of its available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 55 days following each quarter’s end. The Board of Directors of the general partner (the “Board”) declared the following cash distributions to the Partnership’s unitholders for the periods presented: thousands except per-unit amounts Quarters Ended Total Quarterly Per-unit Distribution Total Quarterly Cash Distribution Distribution Date Record Date 2023 March 31 (1) $ 0.856 $ 336,987 May 15, 2023 May 1, 2023 June 30 0.5625 221,442 August 14, 2023 July 31, 2023 September 30 0.575 223,432 November 13, 2023 November 1, 2023 December 31 0.575 223,438 February 13, 2024 February 1, 2024 2024 March 31 $ 0.875 $ 340,858 May 15, 2024 May 1, 2024 June 30 0.875 340,859 August 14, 2024 August 1, 2024 September 30 0.875 340,914 November 14, 2024 November 1, 2024 December 31 0.875 340,996 February 14, 2025 February 3, 2025 2025 March 31 $ 0.910 $ 355,253 May 15, 2025 May 2, 2025 June 30 0.910 355,254 August 14, 2025 August 1, 2025 September 30 0.910 379,521 November 14, 2025 October 31, 2025 December 31 0.910 379,670 February 13, 2026 February 2, 2026 ______________________________________________________________________________________ (1) Includes the regular quarterly distribution of $ 0.500 per unit, or $ 196.8 million, as well as an enhanced distribution of $ 0.356 per unit. The enhanced distribution financial policy adopted in 2022, and paid only in the first quarter of 2023, was discontinued in 2025 and will not be used in future periods to calculate the distribution of available cash. 107 Table of Contents 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 WGRAH, a subsidiary of Occidental, according to the terms of its limited partnership agreement. 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 2023 March 31 (1) $ 342,895 May 2023 June 30 226,260 August 2023 September 30 229,446 November 2023 December 31 229,446 February 2024 2024 March 31 $ 347,675 May 2024 June 30 347,675 August 2024 September 30 347,356 November 2024 December 31 347,356 February 2025 2025 March 31 $ 363,290 May 2025 June 30 363,290 August 2025 September 30 391,568 October 2025 December 31 385,927 February 2026 _______________________________________________________________________________________ (1) Includes amounts related to the enhanced distribution discussed above. In addition to the distributions discussed above, during the year ended December 31, 2023, WES Operating made a distribution of $ 130.1 million to the Partnership and WGRAH. The Partnership used its portion of the distribution to repurchase common units. 108 Table of Contents 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, 2025, Occidental held 165,681,578 common units, representing a 39.7 % 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 2.2 % general partner interest in the Partnership. The public held 242,459,788 common units (including the units issued in connection with the Aris acquisition, see Note 3 ), representing a 58.1 % limited partner interest in the Partnership. See Note 18 . Partnership equity repurchases. In February 2025, the Board authorized the Partnership to buy back up to $ 250.0 million of the Partnership’s common units through December 31, 2026 (the “2025 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, 2025, the Partnership repurchased no common units. As of December 31, 2025, the Partnership had an authorized amount of $ 250.0 million remaining under the program. 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 common units were 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 included 5.1 million common units repurchased from Occidental, for an aggregate purchase price of $ 134.6 million. Holdings of WES Operating equity. On October 15, 2025, WES Operating issued preferred units to Aris, a wholly owned subsidiary of the Partnership, in connection with the Aris acquisition (see Note 1) . As of December 31, 2025, (i) the Partnership, directly and indirectly through its ownership of WES Operating GP, owned a 98.1 % limited partner interest and the entire non - economic general partner interest in WES Operating and (ii) Occidental, through its ownership of WGRAH, owned a 1.9 % 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 following table provides a reconciliation between basic and diluted net income (loss) per common unit: Year Ended December 31, thousands except per-unit amounts 2025 2024 2023 Net income (loss) Limited partners’ interest in net income (loss) $ 1,154,498 $ 1,536,967 $ 998,532 Weighted-average common units outstanding Basic 386,074 380,397 383,028 Dilutive effect of non-vested phantom units 1,806 2,058 1,380 Diluted 387,880 382,455 384,408 Excluded due to anti-dilutive effect — 2 114 Net income (loss) per common unit Basic $ 2.99 $ 4.04 $ 2.61 Diluted $ 2.98 $ 4.02 $ 2.60 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. 109 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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: Statements of operations Year Ended December 31, thousands 2025 2024 2023 Revenues and other Service revenues – fee based $ 2,230,328 $ 2,099,116 $ 1,773,914 Service revenues – product based 39,685 56,688 16,497 Product sales 26,525 5,704 43,683 Total revenues and other 2,296,538 2,161,508 1,834,094 Equity income, net – related parties (1) 85,788 112,385 152,959 Operating expenses Cost of product (2) 4,885 ( 67,414 ) ( 72,903 ) Operation and maintenance 6,999 10,580 4,618 General and administrative 217 350 284 Total operating expenses 12,101 ( 56,484 ) ( 68,001 ) _________________________________________________________________________________________ (1) See Note 7 . (2) Includes related-party natural - gas and NGLs imbalances. Balance sheets December 31, thousands 2025 2024 Assets Accounts receivable, net $ 407,941 $ 401,315 Other current assets 524 6,671 Equity investments (1) 504,859 541,435 Other assets 33,124 41,641 Total assets 946,448 991,062 Liabilities Accounts and imbalance payables 20,639 20,609 Accrued liabilities 14,991 4,717 Other liabilities (2) 631,292 504,415 Total liabilities 666,922 529,741 _________________________________________________________________________________________ (1) See Note 7 . (2) Includes contract liabilities from contracts with customers. See Note 2 . 110 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. RELATED-PARTY TRANSACTIONS Statements of cash flows Year Ended December 31, thousands 2025 2024 2023 Distributions from equity - investment earnings – related parties $ 90,973 $ 111,386 $ 155,169 Contributions to equity investments – related parties — ( 9,690 ) ( 1,153 ) Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850 39,104 Distributions to Partnership unitholders (1) ( 629,946 ) ( 604,512 ) ( 494,127 ) Distributions to WES Operating unitholders (2) ( 29,534 ) ( 25,450 ) ( 22,850 ) Unit repurchases from Occidental (3) — — ( 127,500 ) _________________________________________________________________________________________ (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. 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: Statements of operations Year Ended December 31, thousands 2025 2024 2023 General and administrative (1) $ 4,440 $ 4,130 $ 3,554 _________________________________________________________________________________________ (1) Includes an intercompany service fee between the Partnership and WES Operating. Balance sheets December 31, thousands 2025 2024 Other current assets $ 447 $ 6,263 Other assets 29,957 38,421 Accounts and imbalance payables (1) 76,040 46,773 _________________________________________________________________________________________ (1) Includes balances related to transactions between the Partnership and WES Operating. Statements of cash flows Year Ended December 31, thousands 2025 2024 2023 Distributions to WES Operating unitholders (1) $ ( 1,465,504 ) $ ( 1,272,152 ) $ ( 1,142,217 ) _________________________________________________________________________________________ (1) Represents distributions paid to the Partnership and Occidental, through its ownership of WGRAH, according to the terms of WES Operating’s partnership agreement. The year ended December 31, 2023, included distributions made from WES Operating to the Partnership that were used to repurchase common units. See Note 4 and Note 5. 111 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. RELATED-PARTY TRANSACTIONS 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, NGLs, and water solutions volumes to Occidental. Gathering and processing agreements. The Partnership has significant gathering, treating, processing, stabilization, and produced-water disposal arrangements with affiliates of Occidental on most of its systems. While Occidental is the contracting counterparty of the Partnership, these arrangements with Occidental include not just Occidental - produced volumes, but also, in some instances, the volumes of other working - interest owners of Occidental who rely on the Partnership’s facilities and infrastructure to bring their volumes to market. Natural-gas throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 36 %, 34 %, and 34 % for the years ended December 31, 2025, 2024, and 2023, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 91 %, 91 %, and 86 % for the years ended December 31, 2025, 2024, and 2023, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 61 %, 78 %, and 78 % for the years ended December 31, 2025, 2024, and 2023, respectively. See Note 18. The Partnership has discussed 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. Marketing services. While the Partnership markets and sells substantially all of its crude oil, residue gas, and NGLs directly to third parties, it does still have some marketing agreements with affiliates of Occidental, the activity for which is reflected in the related-party statements of operations above. 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 operating leases for field offices with Occidental as the lessor. Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for field - related costs, field offices, and easements (see Related-party commercial agreement below) supporting the Partnership’s operations at certain assets. General and administrative expense includes amounts accrued for or paid to Occidental for certain reimbursed expenses pursuant to the 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 services 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, between WES Operating GP and Occidental (“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. 112 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. RELATED-PARTY TRANSACTIONS 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 the Partnership amended certain West Texas surface - use and salt - water disposal agreements 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 amended agreements was $ 30.0 million at the time the agreement was executed. As a result of the amendments, (i) these agreements are classified as operating leases and (ii) a 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. 7. EQUITY INVESTMENTS The following tables present the financial statement impact of the Partnership’s equity investments: thousands Percentage Ownership Interest Balance at December 31, 2024 Equity income, net Distributions Distributions in excess of cumulative earnings (1) Balance at December 31, 2025 FRP 33.33 % $ 183,588 $ 45,962 $ ( 47,628 ) $ ( 5,116 ) $ 176,806 Mi Vida 50.00 % 42,765 2,085 ( 2,191 ) ( 10,918 ) 31,741 Red Bluff Express 30.00 % 115,085 16,026 ( 16,026 ) ( 3,290 ) 111,795 Rendezvous 22.00 % 5,639 ( 2,374 ) ( 885 ) ( 2,008 ) 372 TEG 20.00 % 14,496 936 ( 959 ) ( 538 ) 13,935 TEP 20.00 % 170,060 20,008 ( 20,139 ) ( 5,895 ) 164,034 White Cliffs 10.00 % 9,802 3,145 ( 3,145 ) ( 3,626 ) 6,176 Total $ 541,435 $ 85,788 $ ( 90,973 ) $ ( 31,391 ) $ 504,859 _________________________________________________________________________________________ (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. 113 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. EQUITY INVESTMENTS thousands Percentage Ownership Interest Balance at December 31, 2023 Equity income, net Contributions Distributions Distributions in excess of cumulative earnings (1) Acquisitions and Divestitures (2) Balance at December 31, 2024 White Cliffs 10.00 % $ 13,248 $ 3,916 $ — $ ( 3,916 ) $ ( 3,446 ) $ — $ 9,802 Rendezvous 22.00 % 10,815 ( 2,274 ) — ( 985 ) ( 1,917 ) — 5,639 Mont Belvieu JV 25.00 % 88,556 51 — ( 442 ) ( 6,047 ) ( 82,118 ) — TEG 20.00 % 15,185 832 — ( 855 ) ( 666 ) — 14,496 TEP 20.00 % 172,559 27,585 — ( 27,837 ) ( 2,247 ) — 170,060 FRP 33.33 % 186,551 48,726 — ( 46,948 ) ( 4,741 ) — 183,588 Whitethorn LLC 20.00 % 144,799 1,185 — 3,326 ( 4,924 ) ( 144,386 ) — Saddlehorn 20.00 % 101,760 4,200 — ( 4,124 ) ( 3,096 ) ( 98,740 ) — Panola 15.00 % 18,716 74 — ( 74 ) ( 1,021 ) ( 17,695 ) — Mi Vida 50.00 % 45,424 9,126 — ( 10,566 ) ( 1,219 ) — 42,765 Red Bluff Express 30.00 % 106,922 18,964 9,690 ( 18,965 ) ( 1,526 ) — 115,085 Total $ 904,535 $ 112,385 $ 9,690 $ ( 111,386 ) $ ( 30,850 ) $ ( 342,939 ) $ 541,435 _________________________________________________________________________________________ (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. (2) See Note 3 . During the first quarter of 2024, the Partnership closed on the sale of the following equity investments to third parties: (i) the 25.00 % interest in Mont Belvieu JV, (ii) the 20.00 % interest in Whitethorn LLC, (iii) the 15.00 % interest in Panola, and (iv) the 20.00 % interest in Saddlehorn. See Note 3 . The investment balance in White Cliffs at December 31, 2025, is $ 23.9 million less than the Partnership’s underlying equity in White Cliffs’ net assets primarily due to an impairment loss recognized by the Partnership in 2022 that resulted from a decline in value below the carrying value, which was determined to be other than temporary in nature. The investment balance in Rendezvous at December 31, 2025, includes $ 14.1 million for the purchase price allocated to the investment in Rendezvous in excess of the historical 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. 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. 114 Table of Contents 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, thousands 2025 2024 2023 Revenues $ 629,409 $ 699,011 $ 1,572,120 Operating income 339,532 439,052 619,597 Net income 341,305 441,752 623,593 December 31, thousands 2025 2024 Current assets $ 128,067 $ 176,058 Property, plant, and equipment, net 2,106,506 2,186,172 Other assets 2,306 2,349 Total assets $ 2,236,879 $ 2,364,579 Current liabilities $ 50,355 $ 75,130 Non-current liabilities 8,896 7,943 Equity 2,177,628 2,281,506 Total liabilities and equity $ 2,236,879 $ 2,364,579 115 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. INCOME TAXES Accounting Standards Update 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” was adopted on December 31, 2025, using a retrospective approach with no impact to the consolidated statements or additional disclosures. 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 year ended December 31, 2025, the variance from the federal statutory rate was primarily due to the Texas margin tax liability and federal income tax on activities operated through corporate entities. For the year ended December 31, 2024, the variance from the federal statutory rate was primarily impacted by a state margin tax rate increase associated with no longer being included in Occidental’s affiliated group tax return beginning in September 2024 due to Occidental’s sale of 19.5 million of the Partnership’s common units in August 2024 and the resulting decrease in ownership, inclusive of its ownership in WES Operating. For the year ended December 31, 2023, the variance from the federal statutory rate was primarily due to the Texas margin tax liability. The components of income tax expense (benefit) are as follows: Year Ended December 31, thousands 2025 2024 2023 Current state income tax expense (benefit) $ 11,142 $ 3,900 $ 3,341 Total current income tax expense (benefit) $ 11,142 $ 3,900 $ 3,341 Deferred federal income tax expense (benefit) $ 2,492 $ — $ — Deferred state income tax expense (benefit) 1,452 14,211 1,044 Total deferred income tax expense (benefit) $ 3,944 $ 14,211 $ 1,044 Total income tax expense (benefit) $ 15,086 $ 18,111 $ 4,385 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 percentages 2025 2024 2023 Income (loss) before income taxes $ 1,227,541 $ 1,629,363 $ 1,052,392 Statutory tax rate — % — % — % Tax computed at statutory rate $ — $ — $ — Adjustments resulting from: Texas margin tax expense (benefit) (1) $ 12,352 $ 18,111 $ 4,385 Federal income tax on corporate entities 2,492 — — Other state taxes 242 — — Income tax expense (benefit) $ 15,086 $ 18,111 $ 4,385 Effective tax rate 1 % 1 % — % _________________________________________________________________________________________ (1) Includes tax expense of $ 13.1 million for the year ended December 31, 2024, related to an increased Texas margin tax rate resulting from no longer being included in Occidental’s affiliated group tax return beginning in September 2024. 116 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. INCOME TAXES The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows: December 31, thousands 2025 2024 Deferred tax assets: Net operating loss carryforward $ 84,609 $ — Interest expense carryforward and other 4,913 — Other 3,465 2,717 Total deferred tax assets $ 92,987 $ 2,717 Valuation allowance ( 608 ) — Net deferred tax assets $ 92,379 $ 2,717 Deferred tax liabilities: Partnership interest held by corporate subsidiaries $ ( 163,545 ) $ — Depreciable property ( 37,068 ) ( 30,984 ) Other intangible assets ( 3,043 ) ( 1,412 ) Net long-term deferred income tax liabilities ( 203,656 ) ( 32,396 ) Total net deferred income tax liabilities $ ( 111,277 ) $ ( 29,679 ) As of December 31, 2025, the Partnership had unused net operating loss carryforwards for federal income tax purposes of $ 357.3 million, which can be carried forward indefinitely and may be used to offset future taxable income. The federal net operating loss carryforward limit under Internal Revenue Code (“IRC”) Section 382 is $ 322.1 million. Although the Partnership expects to fully utilize the federal net operating loss allowed under IRC Section 382, the amount utilized in a particular year may be limited. As of December 31, 2025, the Partnership had unused net operating loss carryforwards for state income tax purposes of $ 192.3 million, which can be carried forward indefinitely, and $ 13.0 million, which expire from 2038 through 2040. The Partnership believes that it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized and have provided a valuation allowance of $ 0.6 million on the deferred tax assets related to these state net operating loss carryforwards. 117 Table of Contents 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, thousands Estimated Useful Life 2025 2024 Land N/A $ 111,346 $ 13,041 Gathering systems – pipelines 30 Years 6,022,315 5,848,865 Gathering systems – compressors 15 Years 2,835,946 2,718,145 Processing complexes and treating facilities 25 Years 4,311,653 4,046,670 Transportation pipeline and equipment 3 to 48 Years 260,577 257,289 Produced-water disposal and recycling systems 20 Years 2,638,350 1,198,742 Assets under construction N/A 435,953 460,056 Other 3 to 40 Years 1,032,235 967,102 Total property, plant, and equipment 17,648,375 15,509,910 Less accumulated depreciation 6,427,467 5,795,301 Net property, plant, and equipment $ 11,220,908 $ 9,714,609 “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. “Other” property, plant, and equipment primarily represents asset retirement costs, measurement equipment, capitalized interest, electrical distribution equipment, and computer software and equipment. 118 Table of Contents 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 has been allocated to two reporting units: (i) gathering and processing and (ii) transportation. The Partnership recorded $ 348.5 million of goodwill in connection with the Aris acquisition (see Note 3 ). As of December 31, 2025, the carrying value of goodwill for the gathering and processing reporting unit was $ 348.5 million 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, 2025. 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, (ii) contracts assumed in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years, and (iii) contracts assumed in connection with the Aris acquisition, which are being amortized on a straight-line basis over 19 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 2025 2024 Gross carrying value $ 1,275,473 $ 976,629 Accumulated amortization ( 361,715 ) ( 326,889 ) Other intangible assets $ 913,758 $ 649,740 Amortization expense for intangible assets was $ 34.8 million, $ 31.7 million, and $ 31.7 million for the years ended December 31, 2025, 2024, and 2023, respectively. Intangible asset amortization to be recorded in each of the next five years is estimated to be $ 47.4 million per year. 119 Table of Contents 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 Partnership WES Operating December 31, December 31, thousands 2025 2024 2025 2024 Trade receivables, net $ 759,183 $ 701,225 $ 759,183 $ 701,225 Other receivables, net 14,014 613 13,982 589 Total accounts receivable, net $ 773,197 $ 701,838 $ 773,165 $ 701,814 A summary of other current assets is as follows: The Partnership WES Operating December 31, December 31, thousands 2025 2024 2025 2024 NGLs inventory $ 2,733 $ 2,514 $ 2,733 $ 2,514 Materials and supplies 10,103 613 10,103 613 Imbalance receivables 12,220 7,253 12,220 7,253 Prepaid insurance 16,111 15,418 15,540 14,712 Contract assets 3,386 12,358 3,386 12,358 Other 19,700 16,732 19,622 16,325 Total other current assets $ 64,253 $ 54,888 $ 63,604 $ 53,775 A summary of accrued liabilities is as follows: The Partnership WES Operating December 31, December 31, thousands 2025 2024 2025 2024 Accrued interest expense $ 136,006 $ 133,365 $ 136,006 $ 133,365 Short - term asset retirement obligations 9,942 12,830 9,942 12,830 Short-term remediation and reclamation obligations 8,376 2,585 8,376 2,585 Income taxes payable 9,430 4,585 9,430 4,585 Contract liabilities 22,883 11,055 22,883 11,055 Accrued payroll and benefits 69,623 66,563 4,450 — Short-term lease liabilities 65,295 58,897 65,295 58,897 Other (1) 86,820 39,518 70,491 25,272 Total accrued liabilities $ 408,375 $ 329,398 $ 326,873 $ 248,589 _________________________________________________________________________________________ (1) Includes aid-in-construction reimbursement prepayments, other employee expenses, and as of December 31, 2025, Aris-related accruals. 120 Table of Contents 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, thousands 2025 2024 Carrying amount of asset retirement obligations at beginning of year $ 383,025 $ 366,791 Liabilities incurred 56,703 10,060 Liabilities settled ( 7,606 ) ( 5,970 ) Accretion expense 21,524 19,432 Revisions in estimated liabilities ( 15,846 ) ( 7,288 ) Carrying amount of asset retirement obligations at end of year $ 437,800 $ 383,025 Liabilities incurred for the year ended December 31, 2025, primarily related to the acquisition of Aris and expansion activity in West Texas. Revisions in estimated liabilities for the year ended December 31, 2025, primarily related to changes in expected settlement timing for assets in West Texas. Liabilities incurred for the year ended December 31, 2024, primarily related to expansion activity in West Texas. Revisions in estimated liabilities for the year ended December 31, 2024, primarily related to a decrease in expected settlement costs for certain assets in the Rocky Mountains. 121 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. DEBT 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, 2025 December 31, 2024 thousands Principal Carrying Value Fair Value (1) Principal Carrying Value Fair Value (1) Short - term debt 3.100 % Senior Notes due 2025 $ — $ — $ — $ 663,831 $ 663,727 $ 662,457 3.950 % Senior Notes due 2025 — — — 336,758 336,349 335,209 4.650 % Senior Notes due 2026 440,505 440,205 440,923 — — — Finance lease liabilities 8,620 8,620 8,620 10,956 10,956 10,956 Total short - term debt $ 449,125 $ 448,825 $ 449,543 $ 1,011,545 $ 1,011,032 $ 1,008,622 Long - term debt 4.650 % Senior Notes due 2026 $ — $ — $ — $ 440,505 $ 439,637 $ 438,699 4.500 % Senior Notes due 2028 342,935 341,667 344,561 342,935 341,123 336,207 4.750 % Senior Notes due 2028 336,260 335,143 340,517 336,260 334,753 330,483 6.350 % Senior Notes due 2029 600,000 595,551 632,118 600,000 594,270 621,936 7.250 % Senior Notes due 2030 500,000 528,142 533,615 — — — 4.050 % Senior Notes due 2030 1,057,134 1,052,468 1,036,182 1,057,134 1,051,440 992,321 4.800 % Senior Notes due 2031 600,000 594,558 599,994 — — — 6.150 % Senior Notes due 2033 750,000 742,637 796,073 750,000 741,857 764,760 5.450 % Senior Notes due 2034 800,000 791,251 806,936 800,000 790,511 772,536 5.500 % Senior Notes due 2035 600,000 590,713 598,260 — — — 5.450 % Senior Notes due 2044 600,000 594,363 548,040 600,000 594,192 534,096 5.300 % Senior Notes due 2048 700,000 688,259 605,563 700,000 687,990 595,826 5.500 % Senior Notes due 2048 350,000 343,196 309,831 350,000 343,051 304,003 5.250 % Senior Notes due 2050 1,000,000 984,797 858,550 1,000,000 984,494 857,260 Finance lease liabilities 12,425 12,425 12,425 23,329 23,329 23,329 Total long - term debt $ 8,248,754 $ 8,195,170 $ 8,022,665 $ 7,000,163 $ 6,926,647 $ 6,571,456 _________________________________________________________________________________________ (1) Fair value is measured using the market approach and Level - 2 fair value inputs. 122 Table of Contents WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. DEBT Debt activity. The following table summarizes the debt activity for the periods presented: thousands Carrying Value Balance at December 31, 2023 $ 7,901,304 Commercial paper borrowings (repayments), net (1) ( 610,312 ) Issuance of 5.450 % Senior Notes due 2034 800,000 Repayment of 3.100 % Senior Notes due 2025 ( 2,650 ) Repayment of 3.950 % Senior Notes due 2025 ( 12,405 ) Repayment of 4.650 % Senior Notes due 2026 ( 26,699 ) Repayment of 4.500 % Senior Notes due 2028 ( 14,159 ) Repayment of 4.750 % Senior Notes due 2028 ( 46,628 ) Repayment of 4.050 % Senior Notes due 2030 ( 47,459 ) Finance lease liabilities ( 1,819 ) Other ( 1,494 ) Balance at December 31, 2024 $ 7,937,679 Acquisition of 7.250 % Senior Notes due 2030 500,000 Issuance of 4.800 % Senior Notes due 2031 600,000 Issuance of 5.500 % Senior Notes due 2035 600,000 Repayment of 3.100 % Senior Notes due 2025 ( 663,831 ) Repayment of 3.950 % Senior Notes due 2025 ( 336,758 ) Finance lease liabilities ( 13,241 ) Other (2) 20,146 Balance at December 31, 2025 $ 8,643,995 _________________________________________________________________________________________ (1) Net of borrowings and repayments related to commercial paper notes with original maturities of 90 days or less. (2) Includes $ 29.4 million of premiums related to the 7.250 % Senior Notes due 2030. WES Operating Senior Notes. In January 2020, WES Operating issued the 4.050 % Senior Notes due 2030 and 5.250 % Senior Notes due 2050. Including the effects of the issuance prices, underwriting discounts, and interest - rate adjustments, the effective interest rates of the Senior Notes due 2030 and 2050 were 4.169 % and 5.363 %, respectively, at December 31, 2025 and 2024. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. During the fourth quarter of 2025, as part of the acquisition of Aris, WES Operating assumed $ 500.0 million in aggregate principal amount of 7.250 % Senior