Western Midstream (NYSE: WES) expands water assets with $2.0B Aris buy

Rhea-AI Filing Summary

Western Midstream Partners, LP and its subsidiary Western Midstream Operating, LP provide midstream services across Texas, New Mexico, Colorado, Utah, and Wyoming, focusing on natural-gas gathering and processing, crude-oil and NGLs handling, and produced-water management.

The partnership reports extensive infrastructure, including 14,910 miles of pipeline, 5,780 MMcf/d of gas processing and treating capacity, and 6,304 MBbls/d of liquids and water capacity as of December 31, 2025. It operates largely under fee-based contracts with significant minimum-volume commitments to stabilize cash flows.

In 2025, Western Midstream closed a $2.0 billion acquisition of Aris, adding 830 miles of produced-water pipeline, 1,812 MBbls/d of produced-water handling, and 1,560 MBbls/d of recycling capacity, plus 625,000 dedicated acres. The filing highlights a 2025 Purchase Program authorizing up to $250.0 million of unit buybacks and outlines growth projects like North Loving Train II and the Pathfinder produced-water pipeline.

The business remains closely tied to Occidental Petroleum, which owned 39.7% of limited partner interests and supplied 60% of total revenues and the vast majority of crude-oil and produced-water throughput in 2025, creating both strategic advantages and customer-concentration risk.

Insights

Midstream infrastructure and strategy analyst

Large water-focused acquisition and strong Occidental ties reshape Western Midstream’s risk and asset mix.

Western Midstream outlines a sizeable, diversified midstream footprint with 14,910 miles of pipeline and 5,780 MMcf/d of processing and treating capacity across key U.S. basins. Operations are organized as a single segment spanning gas, liquids, and produced water, with most revenues generated under fee-based contracts.

The $2.0 billion acquisition of Aris adds substantial produced-water and recycling assets in the Delaware Basin, including 830 miles of pipeline and 1,812 MBbls/d of handling capacity, deepening Western Midstream’s water-solutions platform. A 2025 Purchase Program authorizes up to $250.0 million of unit repurchases, signaling an explicit capital-return focus.

Strategically, reliance on Occidental is pronounced: for the year ended December 31, 2025, production owned or controlled by Occidental contributed 60% of total revenues and 91% of crude-oil and NGLs throughput. Multiple risk factors emphasize that any weakening in Occidental’s activity, financial position, or strategic focus in core basins could materially affect throughput, revenue stability, and access to capital, making Occidental’s drilling and investment posture a central variable for Western Midstream’s future performance.

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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

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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.

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			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.

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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.

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ASSETS AND AREAS OF OPERATION

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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.

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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.

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COMPETITIVE STRENGTHS

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

•Substantial presence in basins with historically strong producer economics. Our core operating areas are in the Delaware, DJ, and Powder River Basins, which historically have seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas are capable of servicing hydrocarbon production that contains natural gas, crude oil, condensate, and NGLs. Our systems in the Delaware Basin also include significant produced-water 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.

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•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.

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PROPERTIES

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

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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.

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•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.

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•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.

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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.

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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

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(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

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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.

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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.

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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

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(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.

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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.

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TRANSPORTATION

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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

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(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.

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COMPETITION

The midstream services business is extremely competitive, and our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition 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.

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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.

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Our natural-gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural-gas gathering activities, which allows natural-gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil, and criminal remedies. To date, there has been no adverse effect 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;

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•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.

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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

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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

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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 (“CO2e”) 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.

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Item 1A. Risk Factors

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this Form 10-K, and may make in other public filings, press releases, and statements by management, forward-looking statements concerning our operations, economic performance, and financial condition. These forward-looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward-looking” information.

Although we and our general partner believe that the expectations reflected in our forward-looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following:

•our ability to pay distributions to our unitholders and the amount of such distributions;

•our assumptions about the energy market;

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

•our operating results;

•competitive conditions;

•technology;

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

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

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

•weather and natural disasters;

•inflation;

•the availability of goods and services;

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

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

•environmental liabilities;

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

•changes in the financial or operational condition of Occidental;

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

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

•our commitments to capital projects;

•our ability to access liquidity under the RCF and commercial paper program;

•our ability to repay debt;

•the resolution of litigation or other disputes;

•conflicts of interest among us and our general partner and its related parties, including Occidental, with respect to, among other things, and our future business opportunities;

•our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

•our ability to acquire assets on acceptable terms from third parties;

•non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements;

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

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

•cyber attacks or security breaches; and

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

Risk factors and other factors noted throughout this Form 10-K could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Common units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Form 10-K in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, or results of operations could be materially and adversely affected. In such a case, the common units’ trading price could decline, and you could lose part or all of your investment.

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RISKS INHERENT IN OUR BUSINESS

We are dependent on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, 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.

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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.

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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.

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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

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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

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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

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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.

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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

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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.

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We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we therefore are subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in gathering, processing, compressing, treating, and transporting natural gas, crude oil, NGLs, and produced water, including (i) damage to our assets and surrounding properties and disruption of our operations as a result of weather, natural disasters, or acts of terrorism; (ii) inadvertent damage from construction, farm, and utility equipment; (iii) leaks or losses of hydrocarbons or produced water; (iv) fires and explosions; and (v) other hazards that could also result in personal injury, loss of life, pollution, property or natural resource damages, and/or curtailment or suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural-resource damage. These risks also may result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks that may occur in our business. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.

RISKS INHERENT IN AN INVESTMENT IN US

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.

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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

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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.

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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

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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.

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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.

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PART II

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

MARKET INFORMATION

Our common units are listed on the NYSE under the symbol “WES.” As of February 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.

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SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT

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

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

General partner interest. As of December 31, 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.

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

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K.

Discussion of 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.

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•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		%

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OUR OPERATIONS

Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, 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.

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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.

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RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:

																		Year Ended December 31,
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.

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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.

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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.

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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.

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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.

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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.

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RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

Adjusted Gross Margin. We define Adjusted Gross Margin attributable to Western Midstream Partners, LP (“Adjusted Gross Margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product. We believe Adjusted Gross Margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted Gross Margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non-cash equity-based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) 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.

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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.

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																		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.

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																		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 Revenues, 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.

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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.

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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 of $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.

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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.

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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include (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.

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Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities:

						Year Ended December 31,
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.

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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.

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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.

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Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:

						Year Ended December 31,
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.

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CRITICAL ACCOUNTING ESTIMATES

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

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.

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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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity-price risk. Certain of our processing services are provided under percent-of-proceeds and keep-whole agreements. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer, and because some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.

For the year ended December 31, 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 Committee lowered its target range for the federal funds rate three times in 2024 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.

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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, 2025, 2024, and 2023			83
Consolidated Balance Sheets as of December 31, 2025 and 2024			84
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2025, 2024, and 2023			85
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023			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, 2025, 2024, and 2023			89
Consolidated Balance Sheets as of December 31, 2025 and 2024			90
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2025, 2024, and 2023			91
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023			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 18. Subsequent Event			132

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MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s and WES Operating’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

Management assessed the effectiveness of the Partnership’s and WES Operating’s internal control over financial reporting as of December 31, 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

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WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) and Unitholders

Western Midstream Partners, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Midstream Partners, LP and subsidiaries (the Partnership) as of December 31, 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.

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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

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WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) and Unitholders

Western Midstream Partners, LP:

Opinion on Internal Control Over Financial Reporting

We have audited Western Midstream Partners, LP and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 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.

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Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ KPMG LLP

Houston, Texas

February 18, 2026

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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.

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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.

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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.

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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.

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WESTERN MIDSTREAM OPERATING, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP)

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.

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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

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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.

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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.

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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.

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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.

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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).

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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

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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

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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.

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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.

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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.

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4. PARTNERSHIP DISTRIBUTIONS

WES Operating partnership distributions. WES Operating makes quarterly cash distributions to the Partnership and WGRAH, a subsidiary of Occidental, 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.

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5. EQUITY AND PARTNERS’ CAPITAL

Holdings of Partnership equity. The Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “WES.” As of December 31, 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.

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6. RELATED-PARTY TRANSACTIONS

Summary of related-party transactions. The following tables summarize material related-party transactions included in the Partnership’s consolidated financial statements:

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.

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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.

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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.

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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.

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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.

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7. EQUITY INVESTMENTS

The following tables present the summarized combined financial information for equity investments (amounts represent 100% of investee financial information):

						Year Ended December 31,
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

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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.

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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.

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9. PROPERTY, PLANT, AND EQUIPMENT

A summary of the historical cost of property, plant, and equipment is as follows:

												December 31,
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.

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10. GOODWILL AND OTHER INTANGIBLES

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. 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.

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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.

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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.

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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.

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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 Notes due 2030. See Note 3. Also during the fourth quarter of 2025, 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 pay amounts outstanding under its commercial paper program (including borrowings incurred to fund the cash consideration of the acquisition of Aris), and (iii) will be used for general partnership purposes, including the funding of capital expenditures.

During the second quarter of 2025, WES Operating retired the total principal amount outstanding of the 3.950% Senior Notes due 2025 at par value. During the first quarter of 2025, WES Operating retired the total principal amount outstanding of the 3.100% Senior Notes due 2025 at par value. See Debt activity above. As of December 31, 2025, the 4.650% Senior Notes due 2026 were classified as short-term debt on the consolidated balance sheet.

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13. DEBT

During the third quarter of 2024, WES Operating completed the public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034. Net proceeds from the offering were used to repay a portion of the 3.100% and 3.950% Senior Notes due 2025, and for general partnership purposes, including the funding of capital expenditures. In addition, during 2024, WES Operating purchased and retired $150.0 million of certain of its senior notes via open-market repurchases with cash from operations.

As of December 31, 2025, WES Operating was in compliance with all covenants under the relevant governing indentures.

Revolving credit facility. In April 2025, WES Operating exercised an option to extend the maturity date of the RCF from April 2029 to April 2030, for each extending lender. The non-extending lenders’ commitments mature in April 2028 and represent $120.0 million out of $2.0 billion of total commitments, which are expandable to a maximum of $2.5 billion, from all lenders.

The RCF bears interest at an Adjusted Term SOFR (as defined in the RCF amendment), plus applicable margins ranging from 1.00% to 1.70%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Adjusted Term SOFR for a one-month tenor in effect on such day plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.70%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.300% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.

The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related-party transactions, and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA, as defined in the RCF agreement, for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions. As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited.

As of December 31, 2025, there were no outstanding borrowings, resulting in $2.0 billion in effective borrowing capacity under the RCF. Any outstanding commercial paper borrowings (see below) reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its commercial paper program. As of December 31, 2025 and 2024, the interest rate on any outstanding RCF borrowings was 4.99% and 5.63%, respectively. The facility-fee rate was 0.20% at December 31, 2025 and 2024. As of December 31, 2025, WES Operating was in compliance with all covenants under the RCF.

Commercial paper program. In November 2023, WES Operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion. WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings. The maturities of the notes may vary but may not exceed 397 days. As of December 31, 2025, there were no outstanding borrowings under the commercial paper program.

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14. LEASES

Lessee. The Partnership has entered into operating leases for equipment supporting the Partnership’s operations, corporate offices, field offices, and easements, with both Occidental and third parties as lessors. The Partnership has also entered into finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming.

The following table summarizes information related to the Partnership’s leases:

						December 31,
						2025												2024
thousands except lease terms and discount rates						Operating Leases						Finance Leases						Operating Leases						Finance Leases
Assets
Other assets						$	187,916					$	—					$	219,500					$	—
Net property, plant, and equipment						—						20,071						—						33,771
Total lease assets (1)						$	187,916					$	20,071					$	219,500					$	33,771
Liabilities
Accrued liabilities						$	65,295					$	—					$	58,897					$	—
Short-term debt						—						8,620						—						10,956
Other liabilities						110,126						—						143,801						—
Long-term debt						—						12,425						—						23,329
Total lease liabilities (1)						$	175,421					$	21,045					$	202,698					$	34,285
Weighted-average remaining lease term (years)						4						4						4						5
Weighted-average discount rate (%)						5.1						6.8						5.7						7.0

________________________________________________________________________________________

(1)Includes additions to ROU assets and lease liabilities of $24.6 million and $154.1 million related to operating leases for the years ended December 31, 2025 and 2024, respectively. Includes additions to ROU assets and lease liabilities of $3.4 million and $4.3 million related to finance leases for the years ended December 31, 2025 and 2024, respectively.

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14. LEASES

The following table summarizes the Partnership’s lease cost:

						Year Ended December 31,
thousands						2025						2024						2023
Operating lease cost						$	65,379					$	17,086					$	15,457
Short-term lease cost						9,185						58,838						48,343
Variable lease cost						3,501						3,773						3,930
Sublease income						(545)						(587)						(311)
Finance lease cost
Amortization of ROU assets						7,017						7,433						3,487
Interest on lease liabilities						2,182						2,573						1,083
Total lease cost						$	86,719					$	89,116					$	71,989

The following table summarizes cash paid for amounts included in the measurement of lease liabilities:

						Year Ended December 31,
						2025												2024												2023
thousands						Operating Leases						Finance Leases						Operating Leases						Finance Leases						Operating Leases						Finance Leases
Operating cash flows						$	61,933					$	2,156					$	15,627					$	2,573					$	14,217					$	1,083
Financing cash flows						—						16,628						—						6,065						—						3,076

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities at December 31, 2025:

						Operating Leases						Finance Leases
2026						$	66,355					$	8,760
2027						69,876						5,270
2028						13,438						4,986
2029						12,249						3,889
2030						10,925						—
Thereafter						26,777						—
Total lease payments						199,620						22,905
Less portion representing imputed interest						24,199						1,860
Total lease liabilities						$	175,421					$	21,045

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15. EQUITY-BASED COMPENSATION

The general partner has the authority to grant equity compensation awards to its outside directors, executive officers, and employees under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “2017 LTIP”) and the Western Midstream Partners, LP 2021 Long-Term Incentive Plan (the “2021 LTIP”). In connection with the Merger Agreement, all authorized but unused shares that were previously approved for issuance pursuant to the Aris Water Solutions, Inc. 2021 Equity Incentive Plan were adjusted using the applicable exchange ratio for the Merger, assumed by the Partnership, and added to the common unit pool available under the 2021 LTIP. These plans are collectively referred to as the “WES LTIPs.” The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 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.

Common units withheld from an award or surrendered by a participant to satisfy tax withholding obligations or to satisfy the payment of any exercise price with respect to an award will not be considered to be common units delivered under the 2021 LTIP for purposes of the 2021 LTIP Limit. If any award is forfeited, canceled, exercised, settled in cash, or otherwise terminates or expires without the actual delivery of common units, the common units subject to such award will again be available for awards under the 2021 LTIP. The 2021 LTIP provides for the grant of unit options, unit appreciation rights, restricted units, phantom units, other unit-based awards, cash awards, and a unit award or a substitute award to employees and directors of the Partnership and its general partner.

The Board awards phantom units (the “Awards”) to certain members of the leadership team of the Partnership under the WES LTIPs. The Awards include (i) an award of time-vested phantom units that vest ratably over a period of three years (“Time-Based Awards”), (ii) a market-based award that vests after a performance period of three years based on the Partnership’s relative total unitholder return as compared to a group of peer companies (“TUR Awards”), and (iii) a performance award that vests based on the Partnership’s average return on assets over a performance period of three years (“ROA Awards”). At vesting, the number of vested units for the TUR Awards and the ROA Awards will be determined in accordance with the terms of the respective award agreements that provide for payout percentages ranging from 0% to 200% based on results achieved over the applicable performance period. At vesting, the Awards generally will be settled in Partnership common units. Prior to vesting, the Awards granted in 2020 paid in-kind distributions in the form of Partnership common units. During the year ended December 31, 2023, the Partnership issued 3,253 common units as in-kind distributions under such Awards. Prior to vesting, the Time-Based Awards granted after 2020 pay distribution equivalents in cash ratably. The TUR and ROA Awards granted after 2020 pay cash distributions at vesting based on actual performance.

In addition, time-vested phantom units may be awarded under the WES LTIPs to non-executive employees and outside directors of the Partnership, which vest ratably over a period of three years and one year from the grant date, respectively. Prior to vesting, the awards to non-executive employees and outside directors pay distribution equivalents in cash.

The equity-based compensation expense attributable to these awards is amortized over the vesting periods applicable to the awards using the straight-line method. Expense is recognized based on the grant-date fair value and recorded, net of actual forfeitures, as General and administrative expense in the consolidated statements of operations. The fair value of the Time-Based Awards and non-executive awards is based on the observable market price of the Partnership’s units on the grant date of the award. The fair value of the TUR Awards is determined using a Monte Carlo simulation at the grant date of the award. The fair value of the ROA Awards is based on the observable market price of the Partnership’s units on the grant date of the award and compensation expense is adjusted quarterly based on the estimated performance rating at vesting. The total fair value of phantom units vested was $54.7 million, $38.2 million, and $23.4 million for the years ended December 31, 2025, 2024, and 2023, respectively, based on the market price at the vesting date. Compensation expense for the WES LTIPs was $50.8 million for the year ended December 31, 2025, of which $7.3 million was related to the Merger Agreement. For the years ended December 31, 2024 and 2023, compensation expense for the WES LTIPs was $38.0 million and $32.0 million, respectively. As of December 31, 2025, the Partnership had $59.0 million of estimated unrecognized compensation expense attributable to the WES LTIPs that will be recognized over a weighted-average period of 0.9 years.

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15. EQUITY-BASED COMPENSATION

The following table summarizes time-vested award activity under the WES LTIPs:

						2025												2024												2023
						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units
Non-vested units at beginning of year						$	28.96					1,813,764						$	26.24					1,736,702						$	21.33					1,689,030
Granted (1)						39.52						1,379,023						29.39						1,393,972						28.19						1,140,789
Vested						30.44						(1,096,367)						25.25						(1,018,247)						19.66						(910,062)
Forfeited						31.24						(204,518)						27.87						(298,663)						25.73						(183,055)
Non-vested units at end of year						35.54						1,891,902						28.96						1,813,764						26.24						1,736,702

_________________________________________________________________________________________

(1)For the year ended December 31, 2025, includes 513,590 units issued in exchange for Aris equity-based awards.

The following table summarizes TUR Awards activity under the WES LTIPs:

						2025												2024												2023
						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units
Non-vested units at beginning of year						$	38.01					422,888						$	32.22					463,529						$	24.62					388,817
Granted						53.15						181,389						36.15						360,497						40.44						231,395
Vested						37.73						(123,673)						22.77						(304,445)						17.79						(155,052)
Forfeited						37.47						(22,816)						37.28						(96,693)						40.22						(1,631)
Non-vested units at end of year						42.72						457,788						38.01						422,888						32.22						463,529

The following table summarizes ROA Awards activity under the WES LTIPs:

						2025												2024												2023
						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units						Weighted-Average Grant-Date Fair Value						Units
Non-vested units at beginning of year						$	27.78					422,887						$	22.51					463,529						$	18.12					388,817
Granted						41.53						211,648						27.98						407,789						28.48						245,143
Vested						25.95						(153,931)						15.88						(351,737)						16.27						(168,800)
Forfeited						28.32						(22,816)						28.04						(96,694)						28.38						(1,631)
Non-vested units at end of year						32.29						457,788						27.78						422,887						22.51						463,529

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16. COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state, and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. As of December 31, 2025 and 2024, the consolidated balance sheets included $10.0 million and $4.0 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities, and the long-term portion of these amounts is included in Other liabilities. The majority of payments related to these obligations are expected to be made over the next year. See Note 11. As of December 31, 2025, the recorded obligations do not include $6.5 million of anticipated insurance recoveries which are included in Accounts receivable, net.

Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes its environmental obligations are adequate to fund remedial actions required to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the overall results of operations, cash flows, or financial condition. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental issues will not be discovered.

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

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

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17. REPORTABLE SEGMENT

Segment overview. The Partnership’s chief operating decision maker (“CODM”) is the Partnership’s President and Chief Executive Officer who assesses performance and allocates resources on a consolidated basis due to the similar nature of services provided to customers across the Partnership’s domestic asset portfolio. The CODM does not assess performance and allocate resources separately for Western Midstream Operating, LP. Accordingly, the Partnership has a single operating and reportable segment, all the assets of which are in the United States and 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.

Performance measures. Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) is used as the performance measure by the Partnership’s CODM in assessing performance and allocating resources to the Partnership’s single operating and reportable segment. Net income (loss) is the most comparable GAAP metric to the performance metric of non-GAAP Adjusted EBITDA. The Partnership defines 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 the Partnership’s core operating performance, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses.

Adjusted EBITDA is a non-GAAP financial measure that the CODM utilizes to assess (i) the Partnership’s operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis, (ii) the ability of the Partnership’s assets to generate cash flow to make distributions, and (iii) the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. The Partnership’s calculation of Adjusted EBITDA may or may not be comparable to similarly titled measures used by others.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. REPORTABLE SEGMENT

Summarized financial information. The following table presents information about the Partnership’s single operating and reportable segment including (i) total revenues and other, (ii) significant expenses, and (iii) other segment items:

																		Year Ended December 31,
thousands																		2025						2024						2023
Revenues from external customers (1)																		$	3,841,599					$	3,604,138					$	3,105,508
Other revenues																		1,804						1,085						968
Total revenues and other																		3,843,403						3,605,223						3,106,476
Equity income, net – related parties																		85,788						112,385						152,959
Less significant expenses: (2)
Operation and maintenance																		915,896						880,568						762,530
Cash general and administrative costs (3)																		343,305						230,103						198,639
Less other segment items:
Depreciation and amortization																		710,778						650,428						600,668
Interest expense																		390,490						378,513						348,228
Other (income) expense, net (4)																		(16,629)						(31,741)						(5,679)
Income tax expense (benefit)																		15,086						18,111						4,385
Other (5)																		357,810						(19,626)						302,657
Net income (loss)																		$	1,212,455					$	1,611,252					$	1,048,007

_________________________________________________________________________________________

(1)Includes Service revenue - fee based, Service revenue - product based, and Product sales.

(2)The significant expense categories and amounts align with the information that is regularly provided to the CODM.

(3)General and administrative expense as presented in the consolidated statements of operations less non-cash equity-based compensation expense and non-cash amortization of cloud-computing arrangements.

(4)Includes interest income earned on cash and cash equivalent balances.

(5)Other includes: (i) Cost of product, (ii) Non-cash equity-based compensation expense, (iii) non-cash amortization of cloud-computing arrangements, (iv) Property and other taxes, (v) Long-lived asset and other impairments, (vi) Gain (loss) on divestiture and other, net, and (vii) Gain (loss) on early extinguishment of debt.

The CODM uses consolidated total assets as the measure of the Partnership’s single reportable segment assets. As of December 31, 2025 and 2024, the consolidated balance sheets included $15.0 billion and $13.1 billion, respectively, of total assets, which includes $504.9 million and $541.4 million of assets related to equity investments as of December 31, 2025 and 2024, respectively.

Capital expenditures for additions to long-lived assets were $728.0 million, $833.9 million, and $735.1 million for the years ended December 31, 2025, 2024, and 2023, respectively.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

18. SUBSEQUENT EVENT

Subsequent to December 31, 2025, Delaware Basin Midstream LLC (“DBM”), a subsidiary of the Partnership, entered into an amendment (the “GGA Amendment”) to its Delaware Basin gas gathering agreement with Anadarko E&P Onshore LLC (“AEP”), a subsidiary of Occidental, which agreement was originally dated effective January 1, 2018, to, among other things, (i) replace its cost-of-service-based gathering fee structure with a fixed-fee structure, (ii) add a new minimum-volume commitment through the end of 2027, and (iii) modify the process for certain dedication-related acreage transfers and releases. On January 16, 2026, and in connection with the GGA Amendment and related transactions, including an agreement between DBM and a subsidiary of ConocoPhillips pursuant to which DBM will gather and process certain volumes of natural gas already existing on the Partnership’s system, and conforming modifications to the terms of the associated processing arrangements between subsidiaries of the Partnership and Occidental, the Partnership and subsidiaries of Occidental also entered into a unit redemption agreement (“Unit Redemption Agreement”) providing for the transfer to, and redemption by the Partnership, on February 3, 2026, of approximately 15.3 million common units of the Partnership.

Occidental indirectly holds all of the equity interests of the general partner and, following the consummation of the transactions contemplated by the Unit Redemption Agreement, indirectly holds 38.3% of the Partnership’s outstanding common units. The Unit Redemption Agreement and the GGA Amendment and related transactions were reviewed and approved by the Special Committee of the Board of Directors of the general partner, consisting entirely of independent members of the Board of Directors, and, based upon the recommendation of the Special Committee, the full Board of Directors.

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of WES’s general partner and WES Operating GP (for purposes of this Item 9A, “Management”) performed an evaluation of WES’s and WES Operating’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. WES’s and WES Operating’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed in the reports that are filed or submitted under the Exchange Act is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that WES’s and WES Operating’s disclosure controls and procedures were effective as of December 31, 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. As part of the Partnership’s ongoing integration activities, the Partnership is in the process of incorporating the financial information of Aris into its financial reporting controls and procedures. The Consolidated Financial Statements presented in this Form 10-K were prepared using certain information obtained from Aris’s separate legacy systems.

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

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

Changes in Internal Control Over Financial Reporting. There were no changes in WES’s or WES Operating’s internal control over financial reporting during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, WES’s or WES Operating’s internal control over financial reporting.

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Item 9B. Other Information

Amendments to Executive Change in Control Severance Plan

On February 12, 2026, the Western Midstream Partners, LP Executive Change in Control Severance Plan was amended (as amended, the “Amended and Restated Executive CIC Severance Plan”) to, among other things, adopt a form of Transition and Separation Agreement and General Release, which provides for a release of claims and customary restrictive covenants for agreements of this type, including confidentiality, non-disparagement, and non-solicitation of customers, employees, and vendors. The foregoing description of the Amended and Restated Executive CIC Severance Plan is qualified in its entirety by the text of such plan, filed as Exhibit 10.7 to this form 10-K.

Insider Trading Arrangements

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three months ended December 31, 2025, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading arrangement (as defined in Item 408(a)(1)(i) of Regulation S-K) or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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PART III

Item 10. Directors, Executive Officers, and Corporate Governance

Management of Western Midstream Partners, LP

As an MLP, we have no directors or officers. Instead, our general partner manages our operations and activities. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes duties to our unitholders as defined and described in our partnership agreement. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it. The officers of our general partner are also officers of WES Operating GP.

Our general partner’s Board has eight members, four of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed limited partnership, such as us, to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee. Our Board has affirmatively determined that Messrs. Kenneth F. Owen, Robert G. Phillips, and David J. Schulte, and Ms. Lisa A. Stewart are independent as described in the rules of the NYSE and the Exchange Act.

Board Leadership Structure

Occidental owns our general partner and, within the limitations of our partnership agreement and applicable SEC and NYSE rules and regulations, also exercises broad discretion in establishing the governance provisions of our general partner’s limited liability company agreement. Accordingly, our Board structure is established by Occidental.

Although our Board structure has historically separated the roles of Chairperson and Chief Executive Officer (“CEO”), our general partner’s limited liability company agreement and Corporate Governance Guidelines permit the roles of Chairperson and CEO to be combined. Thus, while those roles currently are separated, those roles may be combined in the future.

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Directors and Executive Officers

The biography of each director below contains information regarding that person’s service as a director, business experience, director positions held currently or at any time during the last five years, and involvement in certain legal or administrative proceedings, if applicable, and the experiences, qualifications, attributes, or skills that caused our general partner and its Board to determine that the person should serve as a director of our general partner. In light of our strategic relationship with our sponsor, Occidental, our general partner considers service as an Occidental executive to be a meaningful qualification for service as a non-independent director of our general partner.

The following table sets forth certain information with respect to the directors and executive officers of our general partner as of February 13, 2026.

Name

Age

Position with Western Midstream Holdings, LLC

Peter J. Bennett

58

Chairperson of the Board

Oscar K. Brown

55

President, Chief Executive Officer, and Director

Kristen S. Shults

40

Senior Vice President and Chief Financial Officer

Christopher B. Dial

49

Senior Vice President, General Counsel and Secretary

Catherine A. Green

52

Senior Vice President and Chief Accounting Officer

Daniel P. Holderman

46

Senior Vice President and Chief Operating Officer

Nicole E. Clark

56

Director

Frederick A. Forthuber

62

Director

Kenneth F. Owen

52

Director

Robert G. Phillips

71

Director

David J. Schulte

64

Director

Lisa A. Stewart

68

Director

Our directors hold office until their successors are duly elected and qualified or until the earlier of their death, resignation, removal, or disqualification. Officers serve at the discretion of the Board. There are no family relationships among any of our directors or executive officers.

Peter J. Bennett Houston, Texas Director since: August 2019 Not Independent Biography/Qualifications 
Mr. Bennett has served as a member of our Board since August 2019, as Chairperson of the Board since December 2021, and as a member of the Board’s Compensation Committee since February 2022. Mr. Bennett currently serves as Senior Vice President, Commercial Development, for Occidental Petroleum Corporation. Within this role, Mr. Bennett is responsible for strategic guidance supporting long-term strategy, commercial development and organizational development, and leading teams including New Enhanced Oil Recovery (EOR) Ventures, U.S. Onshore Portfolio Management, and Integrated Land and Power Development. He previously served as President, U.S. Onshore Resources and Carbon Management, and President, Commercial Development at Occidental from October 2020 to February 2026. In this role, Mr. Bennett was responsible for the strategic direction and capital placement for Occidental’s U.S. Onshore Resources and Carbon Management business. Prior to that, he was President and General Manager of Permian Resources and the Rockies. Under his leadership, Permian Resources was the leader in well productivity and capital efficiency in the Permian Basin, one of the leading oil and gas basins in the world. He also oversaw Occidental’s oil and gas operations in the Rockies, where the Company is a leading producer in the DJ Basin. Mr. Bennett has 36 years of industry experience with a strong record of accomplishment in technology, operations and financial leadership. His previous roles also include Senior Vice President of Permian Resources and President and General Manager, Permian Resources New Mexico unit, where he led the business to achieve play-leading performance. Mr. Bennett has also served as Chief Transformation Officer, responsible for aligning technical initiatives, organization and business processes and Vice President, Portfolio and Optimization, pioneering advancements in portfolio and development planning, as well as innovative logistical and operational solutions. As Operations Manager, Permian Enhanced Oil Recovery, he oversaw significant improvements in production, operability and cost. Mr. Bennett joined Oxy as Vice President, Supply Chain - Western Hemisphere, where his responsibilities included global procurement. Prior to joining Oxy in 2004, he held a variety of strategy, operations, supply chain and finance roles with SAIC, Hess and Texaco. Since June 2023, Mr. Bennett has served as the Chairman of the Board of Directors of Net Power Inc., an NYSE listed company focused on renewable energy.

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Oscar K. Brown Houston, Texas Director since: August 2019 Not Independent Officer since: October 2024			Biography/Qualifications Mr. Brown has served as President and Chief Executive Officer of our general partner since October 2024, a member of our Board since August 2019, as Chairperson of the Sustainability Committee from February 2021 to October 2024, and as a member of the Compensation Committee from February 2022 to May 2025. From April 2022 to June 2024, Mr. Brown served as Chief Financial Officer of FREYR Battery, which provided industrial scale clean battery solutions to reduce global emissions. Mr. Brown previously served as Senior Vice President, Strategy, Business Development and Supply Chain of Occidental from November 2018 to March 2020. In this role, Mr. Brown was responsible for, among other things, Occidental’s global business development functions and global supply chain management. Mr. Brown also served as Senior Vice President, Corporate Strategy and Business Development from July 2017 to November 2018. Prior to joining Occidental in 2016, Mr. Brown worked at Bank of America Merrill Lynch, where he most recently served as managing director and co-head of Americas Energy Investment Banking. Mr. Brown served as Occidental’s designated representative on the board of directors of Plains All American Pipeline’s governing entity, PAA GP Holdings LLC (NYSE: PAA and PAGP) from August 2017 to September 2019.
Kristen S. Shults Houston, Texas Officer since: May 2022			Biography/Qualifications Ms. Shults has served as Senior Vice President and Chief Financial Officer of our general partner since May 2022, as Senior Vice President, Finance and Communications of our general partner since May 2021, and as Vice President, Investor Relations and Communications of our general partner since November 2019. Ms. Shults joined Anadarko in 2015 and has over 15 years of experience in the oil and gas industry. During her career at Anadarko, Ms. Shults served in various roles of increasing responsibility throughout Anadarko’s tax organization, including Director of Tax Compliance and Reporting from March 2018 to November 2019 and Worldwide Tax Manager from February 2017 to February 2018. Ms. Shults began her career in the tax practice of Ernst & Young, LLP, and is a Certified Public Accountant.
Christopher B. Dial Houston, Texas Officer since: December 2019			Biography/Qualifications Mr. Dial has served as Senior Vice President, General Counsel and Secretary of our general partner since December 2019. Prior to joining Western Midstream, from January 2018 to September 2019, Mr. Dial served as Senior Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer of the general partner of American Midstream Partners, LP. Mr. Dial also previously spent over 10 years in a number of in-house legal roles, most recently as General Counsel of Susser Holdings II, LP, Associate General Counsel of Susser Holdings Corporation, and Associate General Counsel and Corporate Secretary of Sunoco LP. Mr. Dial began his career as an Associate Attorney in the corporate section of the Houston office of Andrews Kurth, LLP, working on corporate, capital markets, governance, and other transactional matters primarily in the energy industry.
Catherine A. Green Houston, Texas Officer since: October 2019			Biography/Qualifications Ms. Green has served as Senior Vice President and Chief Accounting Officer of our general partner since May 2021, and as Vice President and Chief Accounting Officer of our general partner from October 2019 to May 2021. Ms. Green joined Anadarko in 2001 and served in a variety of roles throughout the accounting and finance organization, including internal audit, technical U.S. GAAP accounting, internal controls, and as Director, Expenditure Accounting from March 2018 to September 2019. Prior to joining Anadarko, Ms. Green began her career as an auditor with Grant Thornton LLP in the United Kingdom and Houston and is a Chartered Accountant with the Institute of Chartered Accountants in England and Wales.
Daniel P. Holderman Houston, Texas Officer since: August 2022			Biography/Qualifications Mr. Holderman has served as Senior Vice President and Chief Operating Officer of our general partner since August 2024, as Senior Vice President, South Operations of our general partner since October 2022, and as Senior Vice President and Co-Chief Operating Officer of our general partner from August 2022 to October 2022. Before joining WES, Mr. Holderman served as Director, Delaware Basin Asset for Oxy USA, Inc., a subsidiary of Occidental, assuming the role in November 2018. Previously, Mr. Holderman had served as the Asset Manager overseeing Occidental’s Midland Basin assets in West Texas, assuming that role in June 2017. Mr. Holderman joined Occidental in December 2013, and held various engineering and operations leadership roles across drilling, completions, and production operations. Prior to joining Occidental, Mr. Holderman had nine years of experience in engineering, upstream operations, and commercial roles with ExxonMobil.

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Nicole E. Clark Houston, Texas Director since: December 2020 Not Independent			Biography/Qualifications  Ms. Clark has served as a member of our Board since December 2020, as a member of the Sustainability Committee since February 2021 and as its Chairperson since October 2024, and as a member of the Compensation Committee since February 2022. Ms. Clark presently holds the position of Vice President, Corporate Secretary, Chief Compliance Officer, and Deputy General Counsel at Occidental, having joined Occidental in 2014. Prior to joining Occidental, Ms. Clark was Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer at a private equity-backed industrial distributor to the energy and petrochemicals markets. Before that, Ms. Clark was a Partner at Vinson & Elkins LLP, where she specialized in mergers and acquisitions, securities regulation and corporate governance. She began her legal career as an Associate with Wachtell, Lipton, Rosen & Katz where she practiced corporate law. Prior to becoming an attorney, Ms. Clark was an auditor at Arthur Andersen LLP.
Frederick A. Forthuber Houston, Texas Director since: December 2021 Not Independent			Biography/Qualifications  Mr. Forthuber has served as a member of our Board and the Sustainability Committee since December 2021. Prior to his retirement on December 31, 2025, he served as President of Oxy Energy Services, LLC, a subsidiary of Occidental. In this role, Mr. Forthuber had global functional responsibility for midstream and marketing of crude oil, natural gas liquids, and natural gas. In addition, Mr. Forthuber had global functional responsibility for Health and Safety. Mr. Forthuber has more than 40 years of industry experience in oil and gas operations. He has held positions of increasing responsibility in engineering and project management since joining Occidental with the acquisition of Altura Energy in 2000. Most recently, he served as Vice President, Worldwide Operations for Occidental Oil and Gas Corporation. Prior to joining Occidental, Mr. Forthuber served in engineering roles for Altura Energy and Exxon. Since June 2023, Mr. Forthuber has served on the Board of Directors of Net Power, Inc., an NYSE listed company focused on renewable energy.
Kenneth F. Owen Houston, Texas Director since: September 2020 Independent			Biography/Qualifications Mr. Owen has served as a member of our Board, Chairperson of the Audit Committee, member of the Special Committee since September 2020, and member of the Sustainability Committee since May 2025. Mr. Owen also serves as Chairman and Chief Executive Officer of South Coast Terminals, one of the largest independent manufacturers of specialty chemicals and lubricant additives in the United States. Mr. Owen previously served as Co-founder, President and Chief Executive Officer of Moda Midstream from 2015 to 2018. Prior to Moda, Mr. Owen was at Oiltanking Partners, where he served as President and Chief Executive Officer of the general partner of Oiltanking Partners, L.P. (NYSE: OILT) and Oiltanking North America (OTNA). Mr. Owen originally joined OTNA in 2011 as Vice President and Chief Financial Officer and led the IPO of Oiltanking Partners. Before he joined Oiltanking, Mr. Owen worked in the energy investment banking groups at Citigroup Global Markets Inc. and UBS Investment Bank, where he advised on mergers and acquisitions, joint ventures, IPOs, and equity and debt transactions primarily for the midstream energy sector.
Robert G. Phillips Houston, Texas Director since: May 2025 Independent			Biography/Qualifications Mr. Phillips has served as a member of our Board, and as a member of the Special Committee and Compensation Committee, since May 2025. Mr. Phillips has 48 years of experience in the energy industry, most recently serving as Founder, Chairman and Chief Executive Officer of Crestwood Equity Partners LP, from its formation in October 2010 until its merger with Energy Transfer LP in November 2023. Prior to founding Crestwood, Mr. Phillips served as the President and Chief Executive Officer of Enterprise Products Partners L.P., as Chairman and Chief Executive Officer of GulfTerra Energy Partners, L.P. (formerly El Paso Energy Partners LP), and as Chairman, President and Chief Executive Officer of Eastex Energy, Inc. Mr. Phillips serves as a director of South Bow Corporation, which transports Canadian crude oil production to refining markets in the US Midwest and Gulf Coast, and as a director of Enstor, Inc., which is the largest privately owned natural gas storage company in the United States. Mr. Phillips has previously served as an independent director of Pride International, Inc. and Bonavista Energy Corporation. Prior to Crestwood’s merger with Energy Transfer, Mr. Phillips served on the board of directors of the Energy Infrastructure Council, where he co-chaired its ESG Committee, which focused on the development and implementation of industry-wide sustainability standards across the midstream sector. From 2021 to 2023, Mr. Phillips served on the National Petroleum Council which advises the United States Department of Energy on oil and gas related matters. Mr. Phillips has also completed the International Directors Programme in corporate governance at INSEAD in Fontainebleau, France.

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David J. Schulte Houston, Texas Director since: September 2020 Independent			Biography/Qualifications Mr. Schulte has served as a member of our Board, Chairperson of the Special Committee, and a member of the Audit Committee since September 2020. From September 2010 to June 2024, Mr. Schulte served on the board of, and as Chief Executive Officer of, CorEnergy Infrastructure Trust, Inc., the first publicly traded energy infrastructure real estate investment trust. Mr. Schulte was also a co-founder and a Managing Director of Tortoise Capital Advisors where, from 2002 to 2015, he served on the investment committee and as a leader of new fund development, and as President of several NYSE listed closed-end funds. With assets under management of $16 billion when he left to lead CorEnergy, Tortoise had been a pioneer in developing funds focused on listed energy infrastructure debt and equity securities, including the first closed-end master limited partnership fund in 2004. Prior to co-founding Tortoise, Mr. Schulte had professional experience in private equity, including energy distribution companies, investment banking, and securities law. Mr. Schulte also served on the board of directors and audit committee for Elecsys Corporation from 1995 to 1999, and on the board of directors and audit committee for Inergy, L.P. from 2001 to 2005. Mr. Schulte is an attorney and Certified Public Accountant (both non-practicing), as well as a Chartered Financial Analyst.
Lisa A. Stewart Houston, Texas Director since: September 2020 Independent			Biography/Qualifications Ms. Stewart has served as a member of our Board, and as a member of the Audit Committee and Special Committee, since September 2020, and as Chairperson of the Compensation Committee since February 2022. Ms. Stewart serves as Executive Chairman of Sheridan Production Partners, a position she has held since April 2020. From the founding of Sheridan in 2006, she served as Chairman, Chief Executive Officer and Chief Investment Officer overseeing all aspects of Sheridan acquisitions and the implementation of Sheridan’s strategy. Ms. Stewart has more than 44 years of experience in the oil and gas industry in engineering and management positions. Prior to founding Sheridan, Ms. Stewart served as Executive Vice President of El Paso Corporation and President of El Paso E&P and other non-regulated businesses. Prior to her time at El Paso, Ms. Stewart spent 20 years at Apache, leaving in January 2004 as Executive Vice President with responsibility for reservoir engineering, business development, land, environmental, health and safety, and corporate purchasing. Ms. Stewart maintains the National Association of Corporate Directors’ Director Certification (NACD.DC) and earned a Certificate in Cybersecurity Oversight issued by the Software Engineering Institute at Carnegie Mellon University. From December 2019 to March 2024, Ms. Stewart served as an Independent Director of Jadestone Energy, an AIM-listed public energy company focused on Southeast Asia. Ms. Stewart is currently a director of Coterra Energy, an NYSE listed energy company focused in the Permian Basin, Anadarko Basin, and Marcellus Shale.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units, and other equity securities. Officers, directors, and greater-than-10-percent unitholders are required by the SEC’s regulations to furnish to us, and any exchange or other system on which such securities are traded or quoted, with copies of all Section 16(a) forms they file with the SEC.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors, and greater-than-10-percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2025, except that on May 19, 2025, a Form 3 was filed in connection with Mr. Phillips’ appointment to the Board on May 4, 2025.

Reimbursement of Expenses of Our General Partner and Its Related Parties

Our general partner does not receive any management fee or other compensation for its management of WES. On December 31, 2019, WES entered into an amended and restated Services Agreement, under which we reimbursed Occidental for administrative services it performed on our behalf through December 31, 2020, with the agreement renewing every six months thereafter for so long as not terminated by either party. Most of the administrative and operational services previously provided by Occidental fully transitioned to us by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement. Read Part III, Item 13 of this Form 10-K for additional information regarding these agreements.

Board Committees

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

Audit Committee. The Audit Committee is composed of three independent directors, Messrs. Owen (Chairperson) and Schulte, and Ms. Stewart, each of whom understands fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under the NYSE listing standards and the Exchange Act. In making the independence determination, the Board considered the requirements of the NYSE and our Code of Ethics and Business Conduct. The Audit Committee held four meetings during 2025.

Mr. Owen has been designated by the Board as the “Audit Committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Owen’s biography set forth above.

The Audit Committee assists the Board in its oversight of the integrity of the consolidated financial statements, internal control over financial reporting, and compliance with legal and regulatory requirements, and the policies and controls of WES and WES Operating. The Audit Committee has the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (iii) establish policies and procedures for the pre-approval of all audit, audit-related, non-audit, and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the Audit Committee and to our management, as necessary.

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

Sustainability Committee. The Sustainability Committee is composed of two non-independent directors, Ms. Clark (Chairperson), and Mr. Forthuber, and one independent director, Mr. Owen. The Sustainability Committee assists the Board in overseeing environmental, social, and governance matters, including those related to sustainability and climate change, that are relevant to the Partnership’s activities and performance, and devoting appropriate attention and effective response to stakeholder concerns regarding such matters.

Compensation Committee. In February 2022, the Board established a compensation committee to assist the Board in evaluating, designing, and recommending to the Board for approval, compensation of our executive officers and non-employee directors. The Compensation Committee is composed of two independent directors, Ms. Stewart (Chairperson) and Mr. Phillips, and two non-independent directors, Ms. Clark and Mr. Bennett. The Compensation Committee held three meetings during 2025.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our Board, our non-management directors meet in an executive session without management participation. Under our Corporate Governance Guidelines, these meetings are chaired on a rotating basis by the chairpersons of the Board’s Audit Committee and Special Committee.

The Board welcomes questions or comments about WES and its operations. Unitholders or interested parties may contact the Board, including any individual director, at BoardofDirectors@westernmidstream.com or at the following address: Name of the Director(s), c/o Secretary, Western Midstream Holdings, LLC, 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380.

Director Attendance

The Board of Directors held six meetings in 2025.

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Insider Trading Policy

We are committed to promoting high standards of ethical business conduct and compliance with applicable laws, rules, and regulations. As part of this commitment, we have adopted our Insider Trading Policy governing the purchase, sale, and/or other dispositions of our securities by our directors, officers, and employees. We believe our Insider Trading Policy is reasonably designed to promote compliance with insider trading laws, rules and regulations, and the exchange listing standards applicable to us. A copy of our Insider Trading Policy is filed as Exhibit 19.1 to this Annual Report on Form 10-K.

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

Our general partner has adopted a Code of Ethics and Business Conduct (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, principal accounting officer, and all other senior financial and accounting officers of our general partner. Our Code of Ethics is also applicable to all WES employees. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, we will disclose the information on our website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.

We make available free of charge, within the “Governance” section of our website at www.westernmidstream.com, and in print to any unitholder who so requests, our Code of Ethics, Corporate Governance Guidelines, Audit Committee charter, Special Committee charter, Sustainability Committee charter, and Compensation Committee charter. Requests for print copies may be directed to investors@westernmidstream.com or to: Investor Relations, Western Midstream Partners, LP, 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380, or telephone (832) 636-1009. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Item 11. Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

This Compensation Discussion and Analysis (“CD&A”) provides a description of the material elements, objectives, and principles of WES’s 2025 executive compensation program for its named executive officers (“NEOs”), recent compensation decisions, and the factors the Compensation Committee and the Board considered in making those decisions.

2025 Named Executive Officers

Oscar K. Brown President and Chief Executive Officer

Kristen S. Shults Senior Vice President and Chief Financial Officer

Daniel P. Holderman Senior Vice President and Chief Operating Officer

Christopher B. Dial Senior Vice President, General Counsel and Secretary

Catherine A. Green Senior Vice President and Chief Accounting Officer

In addition, Robert W. Bourne, former Senior Vice President, Chief Commercial Officer, was identified as a named executive officer for 2025.

Executive Summary

Our strategic objective is to create value for WES unitholders through cost efficiencies, increasing the quality, safety, and reliability of WES’s service offerings, and a balanced approach to distributions, debt reduction, and common unit repurchases. Our compensation program is designed to align the interests of our executive officers with those of our unitholders by providing pay that is linked to the achievement of performance goals established to foster the creation of sustainable, long-term value for WES.

In 2025, our Board took the following key actions related to executive compensation:

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

•Reviewed our annual cash incentive program design and metrics to confirm their continuing alignment with the Partnership’s overall business strategy;

•Approved a discretionary bonus pool for the Partnership’s Senior Vice Presidents, which include the NEOs other than Mr. Brown (the “Discretionary Bonus Pool”); and

•Reviewed the peer group used to benchmark compensation for our executive officers, and made changes, as applicable, to the peer group used to determine the performance of our total unitholder (“TUR”) return incentive awards.

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

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2025 Business and Performance Highlights

2025 was a year of remarkable achievements for WES, as it continued to grow its core businesses and improve its operations. In particular, during the 2025 fiscal year, WES:

•Completed the acquisition of Aris, creating one of the largest, fully-integrated Delaware Basin produced-water solutions providers.

•Achieved year-over-year throughput growth across all products in the Delaware Basin of 9-percent, 6-percent, and 40-percent for natural gas, crude oil and NGLs, and produced water, respectively.

•Sanctioned the long-haul Pathfinder pipeline to transport over 800 MBbls/d of produced water for disposal and reuse opportunities.

•Completed construction of the North Loving I natural-gas processing plant, increasing WES’s operated natural-gas processing capacity in the Delaware Basin by 250 MMcf/d.

•Executed a cost discipline campaign that, excluding the impact of the Aris acquisition, resulted in decreased operation and maintenance expense for the third and fourth quarters compared to the corresponding periods in 2024.

How We Make Compensation Decisions

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

Compensation Philosophy and Objectives of our Compensation Program

Our Board is committed to a compensation philosophy that is designed to align the interests of our executive officers with those of our unitholders by linking compensation to the achievement of performance goals established to foster the creation of long-term value. The Compensation Committee works with its compensation consultant to assist the Board in developing a compensation framework that aligns the interests of our executive officers with those of our unitholders through a culture of equity ownership and an executive compensation program that is more heavily weighted toward at-risk compensation. In developing WES’s executive compensation program, the Compensation Committee intends to design a total compensation package for its executive officers, including the NEOs, that generally provides for, approximately (i) median market annual base compensation, (ii) incentive-based compensation composed of short-term incentives targeted slightly above the median market (i.e., approximately the 50th-60th percentile of market), and (iii) long-term incentives that are targeted to have grant values within the third-quartile of market.

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

The Board and the Compensation Committee believe the design of our executive compensation program, and the Compensation Committee’s decisions and outcomes in 2025, support our compensation philosophy and objectives by ensuring:

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

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

•Compensation aligns with unitholder interests;

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

•Total compensation opportunities are competitive with those offered to other executives across our industry.

Administration of Executive Compensation Program and Methodology

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

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

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

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

•Reviewing and discussing with management the Compensation Discussion and Analysis included in WES’s Annual Report on Form 10-K, and preparing a Compensation Committee Report for inclusion in such 10-K.

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Our Compensation Best Practices. The Board and the Compensation Committee oversee the design and administration of the compensation program for our executive officers. The table below highlights the best practices utilized in our compensation process.

What We Do ü			•Align executive officer pay with performance by structuring at least 84% of pay as at-risk •Emphasize long-term performance in our equity incentive awards •Provide an appropriate mix of fixed and variable pay to encourage retention and increase long-term and sustainable unitholder value •Use appropriate peer group comparisons to determine compensation •Maintain a compensation committee, advised by an independent compensation consultant, that makes recommendations to the Board for approval •Require executive officers to maintain a meaningful equity ownership position via unit ownership •Pay distributions on performance unit awards only at the end of the performance period, based on units earned •Employ a clawback policy governing our incentive-based compensation •Provide for “double trigger” severance benefits in the event of a change of control and qualifying termination
What We Don’t Do X			•Provide excessive perquisites or personal benefits to our executive officers •Allow short-selling or hedging of company securities •Provide excise tax gross-ups •Offer guaranteed bonuses •Have automatic base salary increases

Role of the Compensation Consultant. For the 2025 calendar year, the Compensation Committee retained Zayla Partners as its independent compensation consultant to provide advice on various executive compensation matters. Zayla Partners has served as the Compensation Committee’s consultant since 2023. In 2025, Zayla Partners provided guidance on our benchmarking peer group, TUR performance peer group, pay levels, pay mix, and overall executive compensation program design. The independent executive compensation consultant reports directly to the Compensation Committee and the Board and provides no other material services to us.

Benchmarking Peers. With assistance from Zayla Partners, the Compensation Committee evaluated several factors when determining an appropriate peer group of companies to use for benchmarking 2025 compensation. These factors included: similar midstream businesses of comparable size and scope, comparable executive roles and responsibilities, similar structure (largely independent strategy and governance (whether MLP or corporation)), and companies that are in competition for the same senior executive talent. After careful review, and in consultation with Zayla Partners, the Compensation Committee approved the Partnership’s peer group used to evaluate 2025 compensation decisions. The 2025 benchmarking peer group is listed below:

Antero Midstream Corporation						NiSource Inc.
Cheniere Energy, Inc.						NuStar Energy, L.P. (3)
DT Midstream, Inc.						ONEOK, Inc.
Energy Transfer LP						Plains All American Pipeline, L.P.
EnLink Midstream, LLC (1)						Targa Resources Corp.
Equitrans Midstream Corporation (2)						Tellurian Inc. (4)
Genesis Energy, L.P.						The Williams Companies, Inc.

_________________________________________________________________________________________

(1)EnLink Midstream, LLC was acquired by ONEOK, Inc. as of January 31, 2025.

(2)Equitrans Midstream Corporation was acquired by EQT Corporation as of July 22, 2024.

(3)NuStar Energy, L.P. was acquired by Sunoco, LP as of May 3, 2024.

(4)Tellurian, Inc. was acquired by Woodside Energy Group Ltd as of October 9, 2024.

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Benchmarking Data. To assist in reviewing the design and structure of our executive compensation program, Zayla Partners provided the Compensation Committee with an independent assessment of the compensation programs and practices in our peer group. This assessment included compensation data and program design information that was obtained from the most recent public filings for each peer company. In establishing competitive compensation benchmark levels, Zayla Partners blended the publicly disclosed peer group data with published third-party survey data based on industry and company revenue size. In establishing the general structure and levels of the officers’ compensation packages, the Compensation Committee reviewed 25th, 50th, and 75th percentile benchmark data; however, in making specific officer compensation decisions, the Board has taken into account other considerations as noted above and below.

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

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

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2025 Annual Compensation Program

We believe that compensation for our NEOs should be competitive within our stated peer group and any rewards should be directly linked to the interests of our unitholders. Our executive compensation program includes a mix of direct and indirect compensation elements. The performance metrics for our short-term and long-term incentive programs include a balance of financial, operational and sustainability targets that align with our business strategy. A majority of our executive officers’ total compensation opportunity is performance-based; however, we do not have a specified formula that dictates the overall weighting of each element. Our Board has established an annual target total compensation program designed to support WES’s long-term strategic objectives and be competitive with industry practices.

As illustrated in the charts below, a majority of our executive officers’ targeted annual direct compensation is at-risk, including 88% for our CEO and 84% on average, for our other NEOs. Further, 73% of our current CEO’s targeted annual direct compensation, and on average 72% for our other NEOs, is tied directly to WES’s unit performance through their annual long-term incentive awards.

Targeted Annual Direct Compensation

The charts above are based on the following compensation elements, as discussed under Analysis of 2025 Compensation Actions: base salaries approved in 2025; 2025 target bonus opportunities; and the target value of the 2025 annual long-term incentive awards. The charts do not include allocations to the non-CEO NEOs under the Discretionary Bonus Pool, if any.

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Direct Compensation Elements. WES’s direct compensation program is based on three key elements of compensation: base salary, long-term incentives comprised of equity-based awards, including time-based and performance-based awards, and short-term incentives comprised of an annual cash bonus award. Each element is intended to offer a competitive compensation level relative to our peers that aids in the retention of our executives.

Element

Award

Performance Metrics

Purpose

Base Salary

Cash

N/A

Provides a fixed level of competitive compensation based on performance, expertise, and experience to attract and retain executive talent.

Equity-Based Awards

Time-Based Units (50% of award)

Absolute Unit Price

Time-based Units align with absolute unit price and provide retentive value, especially in a volatile industry.

ROA Units (25% of award)

3-Year Return on Assets

ROA Units reward sustained financial performance by providing an incentive for NEOs to focus on efficiently managing WES’s assets to generate earnings and provide a retentive value.

TUR Units (25% of award)

3-Year Relative Total Unitholder Return

TUR Units reward unit price performance relative to our industry performance peer group, align the interests of our NEOs with that of our unitholders, and provide a retentive value.

Annual Cash Incentives

Company Performance Cash Bonus

Adjusted EBITDA Free Cash Flow System Operability TRIR SIF Volunteer Participation Release Intensity

Based on the achievement of WES’s performance goals, which are aligned with key financial, operational, and sustainability metrics, the annual cash bonus provides incentives for the NEOs to focus and excel in areas aligned with WES’s short-term business objectives.

Discretionary Cash Bonus (Non-CEO NEOs)

Recommendation by the CEO and Compensation Committee to the Board

Based on the achievement of each non-CEO NEO’s individual and team contribution to WES’s performance.

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Analysis of 2025 Compensation Actions

The following is a discussion of the specific actions taken by the Board in 2025 related to each of our direct compensation elements. Each element is reviewed annually, unless circumstances, such as a promotion, other change in responsibilities, significant corporate event or a material change in market conditions, require a more frequent review.

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

Name						Salary Approved in 2024 ($)						Salary Approved in 2025 ($)						% Change
Mr. Brown						950,000						950,000						—		%
Ms. Shults						515,000						545,000						5.8		%
Mr. Holderman						515,000						575,000						11.7		%
Mr. Dial						515,000						520,000						1.0		%
Ms. Green (1)						—						465,000						—		%
Mr. Bourne (2)						515,000						515,000						—		%

________________________________________________________________________________________

(1)Ms. Green was not an NEO for the year 2024.

(2)Mr. Bourne departed from the general partner effective March 3, 2025.

The Board approved the salaries noted above after taking into account the peer benchmark data for the respective positions, and internal compensation alignment considerations for the non-CEO NEOs. The salary increases positioned all but one of the incumbent NEO’s base salary at the median of the peer benchmark data, in line with our stated compensation philosophy of providing annual base compensation that approximates the median of our benchmark peer group. One NEO’s base salary is positioned at the 75th percentile because of internal pay equity considerations.

Equity-Based Long-term Incentive Awards. Our long-term incentive program aligns our NEOs’ interests with those of our unitholders by providing them with the opportunity to earn compensation based on WES’s success. Our Board did not make changes in 2025 to the general structure of our equity-based long-term incentive program, which consists of a combination of time- and performance-based unit awards. This use of both time- and performance-based unit awards is intended to provide a combination of equity-based vehicles that are performance-based in absolute and relative terms while also encouraging retention. Our equity-based long-term incentive program is designed to reward our executive officers for sustained long-term unit performance. This program represents 73% of targeted annual direct compensation for our CEO and an average of 72% for our other NEOs.

Time-Based Units. These units, reflecting 50% of the overall 2025 annual long-term incentive awards for our NEOs, vest annually over a three-year period, subject to the NEO’s continued service through the applicable vesting date. Upon vesting, the awards are settled in WES units. Distribution equivalent rights for time-based awards are paid in cash on a current basis during the vesting period. Our Board has determined that granting time-based units aligns the interests of our NEOs with our unitholders and provides a forfeitable ownership stake to encourage executive retention.

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Return on Asset (“ROA”) Performance Units (“ROA Units”). The Board established ROA as a performance criterion for 25% of the 2025 annual long-term incentive awards made to our non-CEO NEOs. ROA is calculated each year during a three-year performance period as follows:

Adjusted
EBITDA divided by Average
Consolidated Total
Assets

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

WES 3-Year Average ROA			19%			18%			17%			16%			15%			14%			13%			12%			11%
Payout as a % of Target			200%			175%			150%			125%			100%			75%			50%			25%			0%

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

Total Unitholder Return (“TUR”) Performance Units (“TUR Units”). The Board established relative TUR as a performance criterion for 25% of the 2025 annual long-term incentive awards made to our non-CEO NEOs. The units vest based on our TUR performance ranking relative to our peer group over a three-year performance period, with TUR calculated as follows:

Average Closing Common Unit Price for the last 30 trading days of the performance period

minus

Average Closing Common Unit Price for the 30 trading days preceding the beginning of the performance period

plus

Distributions paid per Common Unit over the performance period (based on ex-dividend date)

divided by

Average Closing Common Unit Price for the 30 trading days preceding the beginning of the performance period

For the 2025 TUR awards, Zayla Partners reviewed the industry peer group and recommended adding companies, as appropriate, to expand or replace those that were acquired during the previous year. The industry peer group for our 2025 TUR awards is listed below.

Antero Midstream Corporation						Kinetik Holdings Inc.
DT Midstream, Inc.						MPLX LP
Energy Transfer LP						ONEOK, Inc.
Enterprise Products Partners L.P.						Plains All American Pipeline, L.P.
Genesis Energy, L.P.						Targa Resources Corp.
Hess Midstream LP						The Williams Companies, Inc.
Kinder Morgan, Inc.

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For the 2025 TUR awards, if during the performance period, a peer company files for bankruptcy or fails to meet the listing requirements of the relevant securities exchange, then the Partnership will drop such company to the bottom of the relative TUR percentile ranking. If during the performance period, a peer company is acquired, ceases to exist, ceases to be publicly traded, spins off 25% or more of its assets, or sells all or substantially all of its assets (as applicable, an “Impacted Peer”), then the Compensation Committee may, in its discretion, (i) drop such company out of the peer group and recalculate the results, (ii) applying conventions the Compensation Committee deems appropriate under the circumstances, calculate such company’s ranking position at the time of such event and “freeze” its relative TUR percentile ranking, or (iii) drop such company to the bottom of the relative TUR ranking. The Board’s determination in this regard may be made at any point prior to certifying the performance results of the 2025 TUR awards. This approach grants the Compensation Committee the discretion to address unusual situations affecting our peer companies and ensures that the 2025 TUR awards remain aligned with the Partnership’s compensation philosophy and objectives.

Our payout scale for the 2025 TUR awards strengthens our link to performance by rewarding top quartile performance with a maximum payout of 200% of target and providing for a zero payout for bottom quartile performance. The actual number of TUR Units earned for the three-year performance period will be based on WES’s relative TUR performance during the performance period. For the 2025 TUR awards, the following table reflects the payout scale used to determine the number of TUR Units earned. In the event performance falls between a whole percentile figure listed in the table below, the payout will be interpolated linearly.

WES TUR Payout Schedule

3 Year TUR Performance

< 25th Percentile

≥ 25th Percentile

≥ 50th Percentile

≥ 75th Percentile

Payout Percentage of Target

0%

50%

100%

200%

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

Equity Awards Granted in 2025. In 2025, the Board approved the below annual long-term incentive awards. These awards are included in the Grants of Plan-Based Awards Table. In determining the annual equity awards, and in accordance with our compensation philosophy, the Board took into consideration our peer benchmarking data, internal pay equity, retention concerns, and current NEO unit ownership levels. The target value of the 2025 annual equity awards granted to the incumbent NEOs did not change from their prior year target value. Mr. Brown’s annual long-term incentive award is positioned at the median, the other NEOs’ annual long-term incentive awards are generally positioned between the 50th and 75th percentiles of the benchmark data, with one NEO positioned above the 75th percentile because of internal pay equity considerations.

						Total Target LTI Value ($) (1)						Time-Based Units (50%)												TUR Units (25%)												ROA Units (25%)
Name												Number of Units (#)						Target Value ($)						Number of Units (#)						Target Value ($)						Number of Units (#)						Target Value ($)
Mr. Brown						6,000,000						72,063						3,000,000						36,032						1,500,000						36,032						1,500,000
Ms. Shults						2,500,000						30,026						1,250,000						15,013						625,000						15,013						625,000
Mr. Holderman						2,500,000						30,026						1,250,000						15,013						625,000						15,013						625,000
Mr. Dial						2,500,000						30,026						1,250,000						15,013						625,000						15,013						625,000
Ms. Green						2,000,000						24,021						1,000,000						12,011						500,000						12,011						500,000
Mr. Bourne (2)						1,000,000						12,011						500,000						6,005						250,000						6,005						250,000

_________________________________________________________________________________________

(1)Target LTI values approved by the Board vary from those reported in the Summary Compensation Table and Grants of Plan-Based Awards in 2025 Table, which are calculated in accordance with FASB ASC Topic 718.

(2)In addition to Mr. Bourne’s annual award noted above, he received 39,357 time-based units in connection with his Retirement Agreement.

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Performance Unit Awards — Results for the Performance Period Ended December 31, 2025. In February 2026, the Compensation Committee recommended for certification, and the Board certified, the performance results for the 2023 annual TUR Unit and ROA Unit awards. These awards had a three-year performance period that began on January 1, 2023, and ended December 31, 2025. In determining the treatment of Impacted Peers within the 2023 TUR peer group, the Compensation Committee exercised its discretion under the award agreements and included each Impacted Peer in the results based on their TUR at the time of their relevant transaction. Under the 2023 TUR Unit awards, WES ranked 6th in TUR relative to the established peer group, which resulted in a payout of 156%. Under the 2023 ROA Unit awards, WES achieved a three-year average ROA of 18.6%, which resulted in a payout of 189.2%. Upon the Board’s performance certification, these awards were paid in the form of WES units. The following table lists the target number of performance units awarded and actual performance units earned by the NEOs under the 2023 annual TUR Unit and ROA Unit awards.

						ROA Units												TUR Units
						Paid at 189.2% of Target												Paid at 156% of Target
Name						Number of Units - Target						Number of Units - Earned						Number of Units - Target						Number of Units - Earned
Mr. Brown (1)						—						—						—						—
Ms. Shults						16,228						30,704						16,228						25,316
Mr. Holderman						16,228						30,704						16,228						25,316
Mr. Dial						16,228						30,704						16,228						25,316
Ms. Green						10,526						19,916						10,526						16,421
Mr. Bourne						16,228						30,704						16,228						25,316

_________________________________________________________________________________________

(1)Mr. Brown was not eligible for a grant of performance units in 2023.

Performance-Based Annual Cash Incentives—WES Cash Bonus Program. Our Board has approved the WES Cash Bonus Program (“WCB Program”) under our Incentive Compensation Program. Under the WCB Program, annual cash bonus awards are earned by eligible employees, including our NEOs, taking into account the achievement of specified business objectives and individual performance objectives. The Board maintains full discretion in determining overall performance under the WCB Program and may adjust bonus payouts based on factors it deems relevant.

In February 2025, individual bonus targets were approved by the Board for each of our NEOs as noted in the table below. The target bonuses as a percent of salary did not change from the 2024 targets.

						2025 Target Bonus
Name						$						% of Salary
Mr. Brown						1,187,500						125%
Ms. Shults						436,000						80%
Mr. Holderman						460,000						80%
Mr. Dial						416,000						80%
Ms. Green						372,000						80%
Mr. Bourne (1)						412,000						80%

_________________________________________________________________________________________

(1)Mr. Bourne departed from the general partner effective March 3, 2025.

Our annual incentive program was designed to include measures that support our primary business objective of creating long-term value for our unitholders through continued delivery of profitable operations and increasing returns of capital to stakeholders over time. The overall design and performance metrics under the 2025 WCB Program are generally the same as the 2024 WCB Program, but with changes to its safety and emissions-related sustainability components.

With respect to safety, the Board approved adding a Significant Injury and Fatality (SIF) rate component to the 2025 WCB Program. In doing so, the Board determined that a metric based specifically on significant injuries, as opposed to the broader category of injuries included within TRIR, would further enhance the Partnership’s focus on critical safety processes. The criteria for the SIF performance goal are included in the footnotes to the table below.

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With respect to emissions, the Board approved adding a quantitative Release Intensity component to the 2025 WCB Program. In shifting away from a qualitative performance goal as used in prior years, the Board recognized the Partnership’s year-over-year improvements in its emissions reporting and planning practices, and wished to enhance the Partnership’s focus on quantitative operational improvements based on spill and emissions intensity rates. The method for calculating Release Intensity is discussed in the footnotes to the table below.

The table below reflects the Partnership’s 2025 performance metrics, performance targets and performance under these metrics.

Performance Metric									Relative Weighting Factor						WCB Program Performance Targets						WCB Program Performance Results						Actual Payout %
Financial			Adjusted EBITDA (1)						30%						$2,450.0MM						$2,457.8MM						35%
			Free Cash Flow (2)						30%						$1,375.0MM						$1,407.0MM						49%
System Operability			System Operability (3)						20%						98%						99.4%						40%
Sustainability			TRIR (4)						5%						0.38						0.52						—%
			SIF (5)						5%						1.0						0.0						10%
			Employee Volunteer Participation (6)						4%						50%						68.0%						8%
			Release Intensity (7)						6%						4.56						2.09						12%
									100%																		154%

_________________________________________________________________________________________

(1)Adjusted EBITDA, for purposes of the WCB Program, excludes the effects of revenue recognition cumulative adjustments (see Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K). Performance results reflect reported Adjusted EBITDA of $2,480.8 million, less cumulative catch-up adjustments of $29.5 million and excludes $52.4 million of Aris fourth quarter EBITDA.

(2)Free Cash Flow, for purposes of the WCB Program, excludes the effects of changes in working capital (see Reconciliation of Non-GAAP Financial Measures under Part II, Item 7 of this Form 10-K). Performance results reflect reported Free Cash Flow of $1,526.0 million less working capital changes of $206.3 million and excludes negative Aris Free Cash Flow of $87.3 million (primarily transaction costs, EBITDA, capital, and debt-related costs).

(3)System Operability is a measure of the “real” operability experienced by WES’s customers related to its gas systems, oil systems, and water-disposal wells. It considers the ratio of actual throughput each day to the theoretical maximum throughput available to capture by the applicable system. Loss of throughput due to volumes above firm targets and off-spec product do not count against operability.

(4)TRIR includes injuries or illnesses that result in any of the following: days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness, or death.

(5)SIF includes work-related events resulting in a fatality or permanent, life-altering impairments; a fatality occurring due to a WES safety system failure results in zero achievement of the TRIR and SIF performance goals.

(6)Employee Volunteer Participation includes employee volunteer participation through a WES coordinated event focused on local nonprofit organizations or individual volunteer time through a registered 501(c)(3).

(7)WES set a quantitative sustainability performance goal for Release Intensity, which is calculated as the sum of its release volume to throughput ratios for liquids and gases, respectively. The performance target for 2025 was based on a 5% reduction in Release Intensity relative to 2024.

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2025 WCB Program Performance Assessment. In assessing the Partnership’s performance under the WCB Program, the Board considered our performance against the targets noted in the above table. In determining these results, the Board decided to exclude the impact of the Aris acquisition due to the relatively short ownership period and to provide a clear view of performance against the original targets, without the impact of one-time transaction-related costs. These performance targets were approved by the Board in February 2025. Based upon the results described above and in recognition of the Partnership’s impressive performance across all WCB metrics, including outstanding financial results, sustainability objectives, and customer-focused operational success, the Board approved a payout of 154% under the 2025 WCB Program.

Discretionary Bonus Pool. In 2025, the Board also approved the Discretionary Bonus Pool for the Partnership’s Senior Vice Presidents, which include the NEOs other than Mr. Brown. The Discretionary Bonus Pool is equal to 20% of the aggregate base salaries of each of the Senior Vice Presidents, and may be funded in an amount of up to 40% of such aggregate base salaries (i.e. 20% multiplied by up to 200%). Any Discretionary Bonus Pool allocations shall be based on the recommendation of the CEO and Compensation Committee and are subject to the final approval of the Board.

For the Discretionary Bonus Pool, the Board considered the recommendations of the CEO and the Compensation Committee in reviewing the individual performance of the Senior Vice Presidents. The recommendation for the funding of the Discretionary Bonus Pool was based on the performance of the Senior Vice Presidents (including the NEOs) towards WES’s strong 2025 strategic, operational, and commercial results and the execution of critical WES projects during the year, including the acquisition and integration of Aris, initiation of a successful cost discipline campaign, the completion and sanctioning of key organic growth projects, and the implementation of internal systems improvements. The Discretionary Bonus Pool was allocated among the participating officers as disclosed below in recognition of the cross-functional nature of these and other achievements.

Actual Bonuses Earned for 2025. The cash bonus awards for 2025 for our NEOs are shown in the table below and are reflected in the “Bonus” and “Non-Equity Incentive Plan Compensation” columns of the Summary Compensation Table.

Name						2025 WCB Program Corporate Performance Awards ($) (1)						Discretionary Bonus Pool Allocation ($)						Total Cash Bonus Awards ($)
Mr. Brown						1,828,750			+			N/A			=			1,828,750
Ms. Shults						671,440			+			83,930			=			755,370
Mr. Holderman						708,400			+			88,550			=			796,950
Mr. Dial						640,640			+			80,080			=			720,720
Ms. Green						572,880			+			71,610			=			644,490
Mr. Bourne (2)						—						—						—

_________________________________________________________________________________________

(1)This amount represents the bonuses attributed to WES’s performance against the performance metrics discussed above, calculated as their target bonus for the year multiplied by the 154% performance factor.

(2)Mr. Bourne departed from the general partner effective March 3, 2025.

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Indirect Compensation Elements

As identified in the table below, the Partnership provides certain benefits and perquisites (considered indirect compensation elements) that are considered typical within our industry and necessary to attract and retain executive talent. The value of each element of indirect compensation is generally structured to be competitive within our industry.

Indirect Compensation Element						Primary Purpose
Retirement Benefits						•Attracts talented executive officers and rewards them for extended service •Offers secure and tax-advantaged vehicles for executive officers to save effectively for retirement
Other Benefits (for example, health care, paid time off, disability, and life insurance) and Perquisites						•Enhances executive welfare and financial security •Provides a competitive package to attract and retain executive talent, but does not constitute a significant part of an executive officer’s compensation
Severance Benefits						•Attracts and helps retain executives in a volatile and consolidating industry •Provides transitional income following an executive’s involuntary termination of employment •In the event of a Change in Control, promotes management independence and helps retain, stabilize, and focus the executives

Retirement Benefits. All of our employees, including our NEOs, are eligible to participate in the Western Midstream Savings Plan, a tax-qualified savings plan maintained by WES. In 2021, our Board approved the Western Midstream Savings Restoration Plan, which is a non-qualified deferred compensation plan implemented to provide for the deferral of employer contributions that the participant would have otherwise been eligible for absent the Internal Revenue Code (“IRC”) limitations that restrict the amount of benefits payable under the tax-qualified savings plan.

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

Perquisites. We provide a limited number of perquisites. The expenses related to these perquisites are imputed and considered taxable income to the executive officers, as applicable, and no related tax gross-ups are provided. Perquisites provided include reimbursement of financial counseling, tax preparation, and estate planning services expenses up to $4,000 annually, and reimbursement for the cost of personal excess liability insurance. In addition, WES has a leased interest in an aircraft that is used primarily for business travel; however, limited personal use by executive officers, including travel by family or invited guests, is allowed so long as any incremental costs associated with such personal use is reimbursed by the executive under a time-sharing agreement. For 2025, any incremental costs of the perquisites provided to each NEO that exceeded $10,000 are included in the “All Other Compensation” column and supporting footnotes of the Summary Compensation Table.

Severance Benefits. Each of our NEOs is covered by the Western Midstream Partners, LP Executive Severance Plan (the “ESP”) and the Western Midstream Partners, LP Executive Change in Control Severance Plan (the “CIC Plan”).

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

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

•An annual bonus for the prior year, if unpaid as of the date of termination, and an annual target bonus for the year of termination, prorated based on the participant’s date of termination;

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

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

•Outplacement services for up to nine months; and

•Any accrued, but unused as of the date of the termination, paid time off.

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

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

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

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

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

•Outplacement services for up to nine months; and

•Any accrued, but unused as of the date of the termination, paid time off.

A detailed discussion of the benefits under these plans is included in the Potential Payments Upon Termination or Change of Control section below.

Additional Compensation Policies and Provisions

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

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

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

Position						Multiple of Base Salary
Chief Executive Officer						6
CFO/COO						4
Other Senior Vice Presidents						3

Clawback Provisions. Per the terms of our 2025 long-term incentive awards, if WES is required to prepare an accounting restatement due to the material noncompliance of the Partnership, as a result of misconduct, with any financial reporting requirement under the securities laws, and if the recipient knowingly engaged in the misconduct (whether or not they are an individual subject to automatic forfeiture under Section 304 of the Sarbanes-Oxley Act of 2002), the Board (or delegated Plan Administrator) may determine that the recipient must reimburse WES the amount of any payment in settlement of an award earned or accrued during the twelve-month period following the first public issuance or filing with the Securities and Exchange Commission (whichever first occurred) of the financial document embodying such financial reporting requirement. These clawback provisions are in addition to the provisions of the Clawback Policy for incentive compensation discussed in the following paragraph.

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

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

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

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

Compensation Committee Report

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

The Compensation Committee of Western Midstream Holdings, LLC:

Lisa Stewart, Chairperson

Peter J. Bennett

Nicole E. Clark

Robert G. Phillips

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EXECUTIVE COMPENSATION

Summary Compensation Table

The following table summarizes the compensation amounts for our NEOs for the years ended December 31, 2025, 2024, and 2023.

Name and Principal Position						Year						Salary ($)												Bonus ($) (1)						Stock Awards ($) (2)						Non-Equity Incentive Plan Compensation ($) (3)						All Other Compensation ($) (4)						Total ($)
Oscar K. Brown (5)						2025						950,000												—						6,415,096						1,828,750						157,300						9,351,146
President and						2024						146,154												42,000						6,000,004						438,000						9,500						6,635,658
Chief Executive Officer						2023						—												—						—						—						—						—
Kristen S. Shults						2025						539,231												83,930						2,672,914						671,440						206,609						4,174,124
Senior Vice President and						2024						512,692												236,642						2,685,074						601,520						187,117						4,223,045
Chief Financial Officer						2023						484,615												756,167						2,044,566						216,000						149,836						3,651,184
Daniel P. Holderman (6)						2025						563,462												88,550						2,672,914						708,400						162,053						4,195,379
Senior Vice President,						2024						512,692												308,226						2,685,074						601,520						136,272						4,243,784
Chief Operating Officer						2023						—												—						—						—						—						—
Christopher B. Dial						2025						519,039												80,080						2,672,914						640,640						201,128						4,113,801
Senior Vice President,						2024						512,692												236,642						2,685,074						601,520						188,952						4,224,880
General Counsel and Secretary						2023						488,462												536,167						2,044,566						216,000						198,206						3,483,401
Catherine A. Green (7)						2025						465,000												71,610						2,138,397						572,880						232,139						3,480,026
Senior Vice President,						2024						—												—						—						—						—						—
Chief Accounting Officer						2023						—												—						—						—						—						—
Robert W. Bourne (8)						2025						101,019												—						4,616,736						—						639,338						5,357,093
Former Senior Vice President						2024						512,692												236,642						2,685,074						601,520						240,324						4,276,252
Chief Commercial Officer						2023						488,462												536,167						2,044,566						216,000						243,591						3,528,786

_________________________________________________________________________________________

(1)    For 2023 and 2024, this column reflects (i) the portion of the annual cash bonus awards that is attributed to the Board’s exercise of its discretion in assessing our performance results under the WCB Program for the years ended December 31, 2023 and 2024, respectively, and (ii) for 2023, 2024 and 2025, also includes any allocations to the applicable NEO of the Discretionary Bonus Pool, each as discussed in the Compensation Discussion and Analysis.

(2)    This column reflects the aggregate grant date fair value of time-based units, ROA Units, and TUR Units, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures). The grant date fair value of the time-based units and ROA Units equals the number of units granted multiplied by the WES closing unit price on the grant date. The grant date fair value of the TUR Units is calculated based on a Monte-Carlo valuation on the grant date. Mr. Bourne’s values also include the incremental fair value of awards modified pursuant to the terms of his Retirement Agreement, computed as of the modification date in accordance with FASB ASC Topic 718. The maximum values, assuming a 200% payout of the 2025 ROA unit awards as of the grant date for Mr. Brown, Ms. Shults, Mr. Holderman, Mr. Dial, Ms. Green, and Mr. Bourne, were approximately $3.0 million, $1.2 million, $1.2 million, $1.2 million, $1.0 million, and $2.1 million, respectively. The maximum values, assuming a 200% payout of the 2025 TUR unit awards as of the grant date for Mr. Brown, Ms. Shults, Mr. Holderman, Mr. Dial, Ms. Green, and Mr. Bourne, were approximately $3.8 million, $1.6 million, $1.6 million, $1.6 million, $1.3 million, and $2.8 million, respectively. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For information regarding the awards granted in 2025, see the Grants of Plan-Based Awards in 2025 table.

(3)    This column reflects the portion of the annual cash bonus awards calculated based on our unadjusted performance results pursuant to the WCB Program.

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(4)    The 2025 amounts are detailed in the table below:

Name						Payments by the Partnership to Employee 401(k) Plan and Savings Restoration Plan ($)						Other ($) (i)						Total ($)
Oscar K. Brown (5)						157,300						—						157,300
Kristen S. Shults						206,609						—						206,609
Daniel P. Holderman (6)						162,053						—						162,053
Christopher B. Dial						201,128						—						201,128
Catherine A. Green (7)						232,139						—						232,139
Robert W. Bourne (8)						19,194						620,144						639,338

_________________________________________________________________________________________

(i)    Mr. Bourne’s amount reflects $463,500 in consulting fees, $69,984 pro-rata target bonus for 2025, and $86,660 for the payout of his accrued but unused paid time off balance paid to him pursuant to the terms of his Retirement Agreement.

(5)    Mr. Brown was appointed President and CEO effective October 28, 2024. He was not an NEO for the year ended December 31, 2023.

(6)    Mr. Holderman was not an NEO for the year ended December 31, 2023.

(7)    Ms. Green was not an NEO for the years ending December 31, 2024 and December 31, 2023.

(8)    Mr. Bourne departed from the general partner effective March 3, 2025.

Grants of Plan-Based Awards in 2025

The following table sets forth information concerning annual cash incentive awards, equity incentive plan awards, and unit awards. The equity incentive plan and unit awards were granted pursuant to the Western Midstream Partners, LP 2021 Long-Term Incentive Plan during 2025 to each of the NEOs as described below.

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

Equity Incentive Plan Awards (ROA Units and TUR Units). Values disclosed reflect grant date fair values for ROA Units and relative TUR Units, as discussed in the Compensation Discussion and Analysis. Officers may earn between 0% and 200% of the target awards based on WES’s performance and continued service over a three-year performance period ending December 31, 2027. Performance units earned are settled in the form of common units. The awards include tandem distribution-equivalent rights accrued and paid in cash at the end of the performance period based on actual performance.

Time-Based Unit Awards. Values disclosed reflect grant date fair values for time-based unit awards that, unless otherwise noted, vest ratably over three years beginning on February 12, 2026. The awards include tandem distribution equivalent rights paid in cash on a current basis.

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Grants of Plan-Based Awards

																																																All Other  Unit Awards: Number of Units (#)						Grant Date Fair Value of Unit Awards ($) (3)
												Estimated Future Payouts Under Non-Equity Incentive Plan Awards																		Estimated Future Payouts Under Equity Incentive Plan Awards
Name and Award Type						Grant Date						Threshold ($)						Target ($)						Maximum ($) (1)						Threshold (#) (2)						Target (#)						Maximum (#)
Oscar K. Brown						—						—						1,187,500						—						—						—						—						—						—
Time-Based Units						02/20/2025						—						—						—						—						—						—						72,063						2,999,983
ROA Units						02/20/2025						—						—						—						9,008						36,032						72,064						—						1,500,012
TUR Units						02/20/2025						—						—						—						22,340						36,032						72,064						—						1,915,101
Kristen S. Shults						—						—						436,000						—						—						—						—						—						—
Time-Based Units						02/20/2025						—						—						—						—						—						—						30,026						1,249,982
ROA Units						02/20/2025						—						—						—						3,753						15,013						30,026						—						624,991
TUR Units						02/20/2025						—						—						—						9,308						15,013						30,026						—						797,941
Daniel P. Holderman						—						—						460,000						—						—						—						—						—						—
Time-Based Units						02/20/2025						—						—						—						—						—						—						30,026						1,249,982
ROA Units						02/20/2025						—						—						—						3,753						15,013						30,026						—						624,991
TUR Units						02/20/2025						—						—						—						9,308						15,013						30,026						—						797,941
Christopher B. Dial						—						—						416,000						—						—						—						—						—						—
Time-Based Units						02/20/2025						—						—						—						—						—						—						30,026						1,249,982
ROA Units						02/20/2025						—						—						—						3,753						15,013						30,026						—						624,991
TUR Units						02/20/2025						—						—						—						9,308						15,013						30,026						—						797,941
Catherine A. Green						—						—						372,000						—						—						—						—						—						—
Time-Based Units						02/20/2025						—						—						—						—						—						—						24,021						999,994
ROA Units						02/20/2025						—						—						—						3,003						12,011						24,022						—						500,018
TUR Units						02/20/2025						—						—						—						7,447						12,011						24,022						—						638,385
Robert W. Bourne												—						412,000						—						—						—						—						—						—
Time-Based Units (4)						02/20/2025						—						—						—						—						—						—						12,011						500,018
ROA Units						02/20/2025						—						—						—						1,501						6,005						12,010						—						249,988
TUR Units						02/20/2025						—						—						—						3,723						6,005						12,010						—						319,166
Time-Based Units (5)						02/20/2025						—						—						—						—						—						—						39,357						1,638,432
ROA Units (6)						02/20/2025						—						—						—						4,924						19,694						39,388						—						819,861
TUR Units (6)						02/20/2025						—						—						—						10,695						19,694						39,388						—						1,089,271

_________________________________________________________________________________________

(1)The non-equity incentive plan has a maximum overall funding of 200% of the aggregate target payout for all participants, but there are no individual maximums established. These values exclude any allocation of the Discretionary Bonus Pool to the applicable NEO.

(2)The threshold payout disclosed is 25% of target for the ROA awards and 62% of target for the TUR awards. For the TUR awards, if during the performance period a company is removed from the peer group, then the percentile ranking and threshold payout would be recalculated using the remaining companies, with the threshold payout beginning at 50% of target at the 25th percentile ranking.

(3)The amounts reflect the fair value on the grant date of the awards made to the NEOs in 2025 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(4)This time-based unit award vests ratably over two years, beginning February 12, 2026.

(5)Pursuant to Mr. Bourne’s Retirement Agreement, this award reflects a new grant of time-based units that was granted to replace the units he would have forfeited under his 2023 and 2024 award agreements upon his retirement. The units vest ratably over two years, beginning February 12, 2026. The fair value shown reflects the incremental fair value computed as of the modification date in accordance with FASB ASC Topic 718.

(6)Pursuant to Mr. Bourne’s Retirement Agreement, these awards represent Mr. Bourne’s 2023 and 2024 performance unit awards that were modified to fully vest without proration, rather than vest on a pro rata basis, and become payable at the end of the applicable performance period based on actual performance. The fair value shown reflects the incremental fair value computed as of the modification date in accordance with FASB ASC Topic 718.

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Outstanding Equity Awards at Year-End 2025

The following table reflects outstanding equity awards for each NEO as of December 31, 2025. The market values shown are based on WES’s closing unit price of $39.50 on December 31, 2025.

						Unit Awards
																		Equity Incentive Plan Awards
						Restricted Units (1)												Performance Units (2) (3)
						Number of Units That Have Not Vested (#)						Market Value of Units That Have Not Vested ($)						Number of Unearned Units That Have Not Vested (#)						Market or Payout Value of Unearned Units That Have Not Vested ($)
Name
Oscar K. Brown
Time-Based Units						177,381						7,006,550						—						—
ROA Units						—						—						64,858						2,561,891
TUR Units						—						—						52,607						2,077,977
Kristen S. Shults
Time-Based Units						70,724						2,793,598						—						—
ROA Units						—						—						99,566						3,932,857
TUR Units						—						—						84,659						3,344,031
Daniel P. Holderman
Time-Based Units						70,724						2,793,598						—						—
ROA Units						—						—						99,566						3,932,857
TUR Units						—						—						84,659						3,344,031
Christopher B. Dial
Time-Based Units						70,724						2,793,598						—						—
ROA Units						—						—						99,566						3,932,857
TUR Units						—						—						84,659						3,344,031
Catherine A. Green
Time-Based Units						54,942						2,170,209						—						—
ROA Units						—						—						75,008						2,962,816
TUR Units						—						—						63,898						2,523,971
Robert W. Bourne
Time-Based Units						51,368						2,029,036						—						—
ROA Units						—						—						83,351						3,292,365
TUR Units						—						—						71,508						2,824,566

_________________________________________________________________________________________

(1)The table below shows the vesting dates for the respective time-based units listed in the above Outstanding Equity Awards at Year-End 2025 Table:

Vesting Date						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green						Mr. Bourne
02/12/2026						24,022						35,768						35,768						35,768						26,978						25,684
10/28/2026						52,659						—						—						—						—
02/12/2027						24,021						24,948						24,948						24,948						19,958						25,684
10/28/2027						52,659						—						—						—						—						—
02/12/2028						24,020						10,008						10,008						10,008						8,006						—

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(2)The table below shows the performance periods for the respective ROA Units listed in the above Outstanding Equity Awards at Year-End 2025 Table. The number of outstanding ROA Units for each award is calculated based on WES’s return-on-assets performance as of December 31, 2025, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. As of December 31, 2025, WES’s performance under the ROA awards was 189.2%, 186.7%, and 180.0% for the performance periods ending December 31, 2025, 2026, and 2027, respectively.

Performance Period						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green						Mr. Bourne
1/1/2023 to 12/31/2025 (i)						—						30,704						30,704						30,704						19,916						30,704
1/1/2024 to 12/31/2026						—						41,838						41,838						41,838						33,472						41,838
1/1/2025 to 12/31/2027						64,858						27,024						27,024						27,024						21,620						10,809

_______________________________________________________________

(i)    Payment of these awards, earned for the performance period ending December 31, 2025, were made in February 2026 after the Board’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.

(3)The table below shows the performance periods for the respective TUR Units listed in the above Outstanding Equity Awards at Year-End 2025 Table. The number of outstanding TUR Units for each award is calculated based on WES’s relative total unit return performance ranking as of December 31, 2025, and is not necessarily indicative of what the payout earned will be at the end of each three-year performance period. As of December 31, 2025, WES’s performance under the TUR awards was 156%, 167%, and 146% for the performance periods ending December 31, 2025, 2026, and 2027, respectively.

Performance Period						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green						Mr. Bourne
1/1/2023 to 12/31/2025 (i)						—						25,316						25,316						25,316						16,421						25,316
1/1/2024 to 12/31/2026 (ii)						—						37,424						37,424						37,424						29,940						37,424
1/1/2025 to 12/31/2027 (ii)						52,607						21,919						21,919						21,919						17,537						8,768

________________________________________________________________

(i)    Payment of these awards, earned for the performance period ending December 31, 2025, were made in February 2026 after the Board’s certification of the performance results. These awards are discussed further in the Compensation Discussion and Analysis.

(ii)    The TUR Units outstanding for these awards assume that any Impacted Peer(s) have been dropped to the bottom of the relative peer group ranking for purposes of determining WES’s relative total unitholder performance ranking. The treatment of Impacted Peers is discussed further in the Compensation Discussion and Analysis.

Option Exercises and Units Vested in 2025

The following table reflects information about the aggregate dollar value realized during 2025 by our NEOs for WES awards that vested in 2025.

						Unit Awards
Name						Number of Units  Acquired on Vesting (#) (1)						Value Realized on Vesting ($) (2)
Oscar K. Brown (3)						52,660						2,042,155
Kristen S. Shults						77,762						3,164,597
Daniel P. Holderman						32,814						1,308,294
Christopher B. Dial						60,736						2,472,929
Catherine A. Green						44,230						1,800,560
Robert W. Bourne						62,077						2,525,859

_________________________________________________________________________________________

(1)The number of units acquired on vesting includes the time-based units that vested in 2025 and the units that vested under the 2022 ROA Unit and TUR Unit awards with performance periods ending December 31, 2024, which were settled in 2025.

(2)The value realized on vesting represents the aggregate number of units that vested multiplied by the common unit price on the vesting date. The actual value ultimately realized by the officer, may be more or less than the value disclosed in the above table, depending upon the timing in which he held or sold the units associated with the vesting occurrence.

(3)Values for Mr. Brown exclude the vesting of units he received in his prior role as a non-employee director.

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Pension Benefits for 2025

WES does not have a defined benefit pension plan that provides NEOs a fixed monthly retirement payment. Instead, all salaried employees on the U.S. dollar payroll, including the NEOs, are eligible to participate in the Partnership’s 401(k) plan, a tax-qualified defined contribution plan.

Nonqualified Deferred Compensation for 2025

The Partnership maintains the Western Midstream Savings Restoration Plan to provide a supplemental benefit to eligible employees, including the NEOs, equal to the excess, if any, of the Partnership contributions that would have been allocated to a participant’s 401(k) plan account each year without regard to IRC limitations. Eligible compensation includes base salary earnings and annual WCB Program payments. Participants may direct contributions into investment options that mirror those provided under the Partnership’s 401(k) Plan. In general, deferred amounts are distributed to the participant in lump sum upon separation from service.

Name						Executive Contributions in 2025						Partnership Contributions in 2025 (1)						Aggregate Earnings / Losses in 2025						Aggregate Withdrawal / Distributions in 2025						Aggregate Balance at End of 2025 (2)
Oscar K. Brown						$	—					$	118,800					$	—					$	—					$	118,800
Kristen S. Shults						—						160,109						55,616						—						484,317
Daniel P. Holderman						—						123,553						26,533						—						289,861
Christopher B. Dial						—						154,628						77,673						—						657,000
Catherine A. Green						—						185,639						88,867						—						760,597
Robert W. Bourne (3)						—						—						60,003						654,093						—

_________________________________________________________________________________________

(1)Reflects contributions earned for fiscal year 2025, although not credited to participant accounts until 2026. These contributions are reported in the Summary Compensation Table for each of the NEOs under the “All Other Compensation” column for the year 2025.

(2)The balance for each NEO includes Partnership contributions previously reported in the Summary Compensation Table for fiscal years prior to 2025 in the following aggregate amounts: Mr. Brown - $0; Ms. Shults - $251,626; Mr. Holderman - $98,322; Mr. Dial - $383,738; Ms. Green - $104,397; and Mr. Bourne - $554,174.

(3)Mr. Bourne departed from the general partner effective March 3, 2025.

Potential Payments Upon Termination or Change of Control

The following discussion provides information regarding the compensation payable to our NEOs under each termination scenario described below, assuming that the applicable termination event occurred on December 31, 2025, and based on the plans and agreements in place on that date. For Mr. Bourne, the values reported reflect the actual payments he was entitled to upon his departure from the general partner in 2025.

On February 18, 2025, Mr. Bourne entered into a Retirement Agreement and General Release (the “Retirement Agreement”) with the Partnership. Pursuant to the terms of the Retirement Agreement, Mr. Bourne continued his employment with the Partnership in the role of advisor through March 3, 2025 (the “Retirement Date”). Through the Retirement Date, Mr. Bourne (a) continued to receive his then current base salary and (b) was eligible to receive a full annual cash bonus for 2024, subject to achievement of the applicable performance conditions. Mr. Bourne continued to participate in the employee benefit plans and programs of the Partnership through the Retirement Date pursuant to their terms. Following the Retirement Date, Mr. Bourne was engaged by the Partnership as a consultant for a six-month period beginning March 4, 2025, and received consulting fees totaling $463,500.

As of the Retirement Date, Mr. Bourne became entitled to receive certain payments and benefits (collectively “Retirement Benefits”), subject to continued compliance with the terms of the Retirement Agreement. The Retirement Benefits included the following: (a) a pro rata cash bonus for 2025 in the amount of $69,984; (b) pro rata vesting on the Retirement Date of Mr. Bourne’s then-outstanding time-vested equity awards, valued at $52,929; (c) eligibility for full vesting, without proration, of Mr. Bourne’s then-outstanding TUR and ROA performance awards, subject to, and adjusted by, the achievement of any performance conditions determined as set forth in the applicable award agreements, (d) a new time-vested award with an estimated value of $2.1 million that vests over two years, (e) a TUR award with a target value of $250,000 and an ROA award with a target value of $250,000, each subject to performance conditions over a three-year period that are consistent with such conditions in prior awards. The estimated value of these outstanding awards as of December 31, 2025, is $8,145,967, which includes his unvested time-based units and unvested performance units, based on performance to date. (f) upon his retirement he also was paid his earned and vested balance of $654,093 in the Western

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Midstream Savings Restoration Plan, and (g) continued participation in the Partnership’s basic life, medical and dental plans at the same rates and levels in accordance with the terms of such plans for a two-year period beginning on the Retirement Date, valued at $47,824. The Retirement Agreement also included a release of claims, as well as confidentiality, cooperation, non-competition, and non-solicitation covenants, and other provisions customary for an agreement of this type, with varying restricted periods ranging from 12 to 24 months.

The following tables reflect potential payments to our NEOs under the ESP, CIC Plan, and award agreements for various scenarios involving a change of control or termination of employment of each NEO, assuming a termination date of December 31, 2025, and, where applicable, using the closing price of our common unit of $39.50 (as reported on the NYSE as of December 31, 2025). In addition to the reported amounts, following a separation from service, NEOs would also receive any previously earned but not paid benefits under our Savings Restoration Plan, as disclosed in the Nonqualified Deferred Compensation for 2025 Table.

Involuntary For Cause. “Cause” for purposes of the ESP is generally defined as: (i) commission of a felony or of a misdemeanor involving fraud, theft or moral turpitude, (ii) habitual neglect of or willful failure to perform duties or responsibilities, (iii) engaging in conduct which is injurious (monetarily or otherwise) to the Partnership (or any affiliates), (iv) engaging in business activities which are in conflict with the business interests of the Partnership (or any affiliates), (v) insubordination, (vi) engaging in conduct which is in violation of any applicable policy or work rule, (vii) engaging in conduct in violation of applicable safety rules or standards, (viii) engaging in conduct that materially discredits, is detrimental to, or is otherwise materially harmful to the Partnership, or (ix) engaging in conduct that is in violation of the applicable Code of Ethics and Business Conduct. Certain notice and cure conditions, as set forth in the ESP, apply in order to make a termination for “Cause” effective. “Cause” for purposes of the CIC Plan is generally defined as: (i) conviction of a felony or of a misdemeanor involving moral turpitude, (ii) willful failure to perform duties or responsibilities, (iii) engaging in conduct which is injurious (monetarily or otherwise) to the Partnership (or any affiliates), (iv) engaging in business activities which are in conflict with the business interests of the Partnership (or any affiliates), (v) insubordination, (vi) engaging in conduct which is in violation of any applicable policy or work rule, (vii) engaging in conduct in violation of applicable safety rules or standards, or (viii) engaging in conduct that is in violation of the applicable Code of Ethics and Business Conduct.

Mr. Brown

Ms. Shults

Mr. Holderman

Mr. Dial

Ms. Green

Cash Severance

$

—

$

—

$

—

$

—

$

—

Total

$

—

$

—

$

—

$

—

$

—

Involuntary Not For Cause Termination or Good Reason Termination under the ESP. As of December 31, 2025, the NEOs below were eligible for severance benefits under the ESP. “Good Reason” for purposes of the ESP is generally defined as the occurrence of any of the following conditions: materially and adversely diminished duties and responsibilities; a material reduction in base salary or base salary plus annual target bonus, unless such reduction is applied generally and consistently to the Partnership’s executives; or a material change in work location. Certain notice and cure conditions, as defined in the ESP, apply in order for a termination for Good Reason to be effective.

						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green
Cash Severance (1)						$	4,275,000					$	1,471,500					$	1,552,500					$	1,404,000					$	1,255,500
Pro-Rata Annual Cash Bonus (2)						1,187,500						436,000						460,000						416,000						372,000
Pro-Rata Vesting of WES Equity Awards (3)						2,593,531						6,081,657						6,081,657						6,081,657						4,473,573
Continuation of Welfare Benefits (4)						46,404						44,654						44,784						44,546						44,309
Total						$	8,102,435					$	8,033,811					$	8,138,941					$	7,946,203					$	6,145,382

_________________________________________________________________________________________

(1)Reflects amounts payable in lump sum pursuant to the terms of the ESP. Mr. Brown’s value reflects 2.0 times the sum of his current base salary plus target bonus. The values for Mses. Green and Shults; Messrs. Dial and Holderman reflect 1.5 times the sum of their current base salary plus target bonus.

(2)The amounts reflect a prorated annual target bonus, assuming each NEO’s employment terminated on December 31, 2025.

(3)The amounts reflect the estimated current value of a prorated portion of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2025. In the event of an involuntary termination not for cause or a “Good Reason” termination, the performance units would be paid after the end of the performance period, based on actual performance. Amounts include the value of the 2023 annual performance unit awards with performance periods that ended December 31, 2025, but that were not settled until February 2026.

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(4)The amounts reflect the continuation of welfare benefits for two years at employee rates. The NEOs are also eligible for reimbursement of outplacement services for up to nine months following their separation.

Change of Control: Involuntary Termination or Voluntary For Good Reason. The following table reflects benefits payable under the CIC Plan to the NEOs in the event of (i) a change of control of WES and (ii) a subsequent qualifying termination event.

Under the CIC Plan, a change in control is deemed to have occurred in the event that: (i) any person or group other than the Partnership or Occidental (or affiliate) acquires 50% or more of the voting power in the Partnership or general partner; (ii) the approval of the Partnership’s plan of liquidation; (iii) the sale, transfer or other disposition of all or substantially all of the Partnership’s assets; (iv) certain changes are made to the composition of the Partnership’s Board of Directors; (v) the completion of a business combination transaction in which, after giving effect to such transaction, neither the Partnership, Occidental, nor its affiliates meet certain ownership thresholds; (vi) the general partner is removed or the general partner (or its affiliate) ceases to be the sole general partner of the Partnership; or the Partnership is taken private in a transaction in which its common equity securities cease to be listed on a national securities exchange.

Under the CIC Plan, Good Reason is generally defined as the occurrence of any of the following conditions without the participant’s consent: (i) diminution of duties and responsibilities; (ii) material reduction in compensation; (iii) change in work location of more than 50 miles; or (iv) in connection with a Change in Control, the failure by the acquiror to assume the Plan. Certain notice and cure conditions, as defined in the CIC Plan, apply in order for a termination for Good Reason to be effective.

						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green
Cash Severance (1)						$	6,391,125					$	1,962,000					$	2,070,000					$	1,872,000					$	1,674,000
Pro-Rata Annual Cash Bonus (2)						1,828,750						671,440						708,400						640,640						572,880
Accelerated Vesting of WES Equity Awards (3)						11,646,418						10,070,486						10,070,486						10,070,486						7,656,996
Continuation of Welfare Benefits (4)						46,404						44,654						44,784						44,546						44,309
Total						$	19,912,697					$	12,748,580					$	12,893,670					$	12,627,672					$	9,948,185

_________________________________________________________________________________________

(1)Reflects amounts payable in lump sum under the CIC Plan. Mr. Brown’s value is calculated as 2.99 times his base salary plus target bonus. The values for Mses. Green and Shults, and Messrs. Dial and Holderman are calculated as 2.0 times their base salary plus target bonus.

(2)Per the terms of the CIC Plan, the NEOs are eligible for a prorated bonus for the year of termination, based on the greater of target performance and actual performance. The amounts reflect their actual bonuses awarded for 2025 under the WCB Program, as discussed in the Compensation Discussion and Analysis and exclude any amounts awarded under the Discretionary Bonus Pool.

(3)The amounts reflect the estimated current value of unvested time-based units and unvested performance units, based on performance to date, unless performance to date was below target, in which case we have assumed target performance, all as of December 31, 2025. In the event of a change of control, the performance would be calculated based on the change of control date. Amounts include the value of the 2023 annual performance unit awards with performance periods that ended December 31, 2025, but were not settled until February 2026.

(4)The amounts reflect the continuation of welfare benefits for two years at employee rates. The NEOs are also eligible for reimbursement of outplacement services for up to nine months following their separation.

Death or Termination due to Disability

						Mr. Brown						Ms. Shults						Mr. Holderman						Mr. Dial						Ms. Green
Accelerated Vesting of WES Equity Awards (1)						$	11,646,418					$	10,070,486					$	10,070,486					$	10,070,486					$	7,656,996
Total						$	11,646,418					$	10,070,486					$	10,070,486					$	10,070,486					$	7,656,996

______________________________________________________________________________________

(1)The amounts reflect the estimated current value of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2025. In the event of death or termination due to disability, the performance units would be paid after the end of the performance period, based on actual performance. Amounts include the value of the 2023 annual performance unit awards with performance periods that ended December 31, 2025, but were not settled until February 2026.

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CEO Pay Ratio

In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of our employees and the annual total compensation of Oscar K. Brown, our President and CEO.

For the 2025 calendar year, the annual total compensation of Mr. Brown, as reported in the Summary Compensation Table for this Item 11, was $9,351,146. The annual total compensation for our median employee, calculated using the same methodology used for our NEOs in the Summary Compensation Table was $173,572. Based on this information, for 2025, Mr. Brown’s total annual compensation was 54 times the annual total compensation of the median employee. In preparing this pay ratio disclosure, we took the following steps:

•We determined that, as of December 31, 2025, our employee population consisted of 1,704 individuals, with all of these individuals located in the United States (as reported in the Human Capital Resources section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K). This population consisted of all employees, whether employed on a full-time or part-time basis.

•In compliance with the regulations, for the year ended December 31, 2025, we are utilizing the same employee previously identified for our 2023 and 2024 pay ratio disclosure. This median employee, was determined using base salary earnings for all employees, excluding our CEO, who were employed by us on December 31, 2023. We included all employees on this effective date, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions, or adjustments to the data in identifying the median employee. The methodology used in identifying the median employee is consistent with the methodology we used in prior years. On October 15, 2025, we completed our acquisition of Aris Water Solutions, Inc. (“Aris”), and as allowed under the regulations, we did not include the approximately 233 former Aris employees in our ratio calculation, as these employees did not participate in our compensation programs or move onto our human resources information systems until January 2026. There were no changes during the year ended December 31, 2025, with respect to our employee compensation arrangements or to the previously identified median employee’s circumstances that we reasonably believe would result in a significant change to our pay ratio disclosure.

•With respect to calculating the total annual compensation disclosed above for the median employee, we combined all of the elements of such employee’s total compensation for 2025.

•The pay ratio disclosed above is a reasonable estimate calculated in accordance with SEC rules, based on our records and the methodologies described above. The SEC rules for identifying the median compensated employee and calculating the pay ratio allow companies to use a variety of methodologies and apply various assumptions. The application of various methodologies may result in significant differences in the results reported by other SEC reporting companies. As a result, the pay ratio reported by other SEC reporting companies may differ substantially from, and may not be comparable to, the pay ratio we disclose above.

Accounting Restatements and Recovery Actions Under Clawback Policy

Item 402(w) of Regulation S-K (“Item 402(w)”) requires the Partnership to make certain disclosures in the event the Partnership is required to prepare an accounting restatement. As of December 31, 2025, the Partnership has not been required to prepare an accounting restatement. Therefore, no disclosures under Item 402(w) are required.

Option Awards and Material Nonpublic Information

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

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Director Compensation

Non-employee directors receive a combination of cash and stock-based compensation designed to attract and retain qualified candidates to serve on our Board. Officers or employees of Occidental who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. During 2025, the non-employee directors of our general partner received compensation for their Board service pursuant to a director compensation plan approved by the Board. To assist in the 2025 annual review of director compensation, the Board directly retained Zayla Partners to provide benchmark compensation data and recommendations for the design of our non-employee director compensation program for the 2025 calendar year. Following such review, the Board approved an increase in the value of the annual phantom unit grant to $160,000. No other changes to director compensation were recommended for 2025.

Accordingly, compensation for non-employee directors during 2025 consisted of the following:

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

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

•an annual grant of phantom units with a grant date fair value of approximately $160,000.

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

Equity Ownership Guidelines. Non-employee directors of the general partner are required to hold common units, phantom units, or related grants of such securities under the Partnership’s long-term incentive plans which have an aggregate value equivalent to three times the annual Board cash retainer. Directors have five years from the date of their initial election to the Board to comply with this requirement. Each non-employee director is currently in compliance with these ownership guidelines.

The following table sets forth information concerning total director compensation earned during 2025 by each non-employee director:

Name						Fees Earned or Paid in Cash ($)						Stock Awards  ($) (1)						Total ($)
Kenneth F. Owen						135,313						159,984						295,297
Robert G. Phillips (2)						74,852						160,019						234,871
David J. Schulte						134,000						159,984						293,984
Lisa A. Stewart						136,000						159,984						295,984

________________________________________________________________________________________

(1)The amounts included in the Stock Awards column represent the grant date fair value of phantom units made to directors in 2025, computed in accordance with FASB ASC Topic 718, based on the value of our common units on grant date. See the table below for phantom units awarded to each non-employee director during 2025. As of December 31, 2025, Messrs. Owen, and Schulte and Ms. Stewart each had 3,843 outstanding phantom units and Mr. Phillips had 4,046 outstanding phantom units.

(2)Mr. Phillips was appointed to the Board on May 5, 2025.

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The table below contains the grant date fair value of phantom unit awards made to each non-employee director during 2025:

Name						Grant Date						Phantom  Units  (#) (1)						Grant Date Fair  Value of Stock Awards ($) (2)
Kenneth F. Owen						February 20						3,843						159,984
Robert G. Phillips (3)						May 15						4,046						160,019
David J. Schulte						February 20						3,843						159,984
Lisa A. Stewart						February 20						3,843						159,984

_________________________________________________________________________________________

(1)The phantom units granted in 2025, vested in full on February 12, 2026. Directors received distribution equivalent rights, paid in cash on a quarterly basis, during the vesting period.

(2)The amounts included in the Grant Date Fair Value of Stock Awards column represent the grant date fair value of the awards made to non-employee directors in 2025 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the value included above.

(3)Mr. Phillips was appointed to the Board on May 5, 2025 and received his annual grant following his appointment.

Compensation Committee Interlocks and Insider Participation

While WES does have a Compensation Committee, our Board continues to make substantive compensation decisions for our executive officers at the recommendation of the Compensation Committee. Mr. Bennett and Ms. Clark, who are directors of our general partner, are also executive or corporate officers of Occidental. However, all compensation decisions with respect to each of these persons are made by Occidental, and none of these individuals receive any compensation directly from us or our general partner for their service as directors. Read Part III, Item 13 below in this Form 10-K for information about relationships among us, our general partner, and Occidental.

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

The following table sets forth the beneficial ownership of our common units held by the following as of February 13, 2026:

•each member of the Board;

•each named executive officer of our general partner;

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

•Occidental and its affiliates.

Name and Address of Beneficial Owner (1)

Common Units Beneficially Owned

Percentage of Common Units Beneficially Owned

Occidental Petroleum Corporation (2)

150,374,176

38.2%

Peter J. Bennett

—

*

Oscar K. Brown

85,440

*

Christopher B. Dial (3)

225,015

*

Daniel P. Holderman

91,384

*

Nicole E. Clark

—

*

Frederick A. Forthuber

—

*

Catherine A. Green

115,036

*

Kenneth F. Owen

41,772

*

Robert G. Phillips

4,046

*

David J. Schulte

40,072

*

Kristen S. Shults

143,752

*

Lisa A. Stewart

39,772

*

All directors and executive officers as a group (12 persons)

786,289

*

_________________________________________________________________________________________

*Less than 1%.

(1)The address for Occidental and its representatives on the Board of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380.

(2)Occidental is the ultimate parent company of each of the following entities and may, therefore, be deemed to beneficially own the units held by such entities. Western Gas Resources, Inc. owns 140,912,118 common units, APC Midstream Holdings, LLC owns 457,849 common units, and Anadarko USH1 Corporation owns 9,004,209 common units of WES.

(3)Common units are held in a margin account.

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The following table sets forth owners of 5% or greater of our common units, other than Occidental and its affiliates, the holdings of which are listed in the first table of this Item 12.

Title of Class

Name and Address of Beneficial Owner

Amount and Nature of Beneficial Ownership

Percent of Class

Common Units

ALPS Advisors, Inc. 1290 Broadway, Suite 1100 Denver, CO 80203

35,074,357 (1)

8.60%

_________________________________________________________________________________________

(1)Based upon its Schedule 13G/A filed January 6, 2026, with the SEC with respect to Partnership securities held as of December 31, 2025, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 35,074,357 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 34,658,430 of the common units held by ALPS.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information with respect to the securities that may be issued under the WES LTIPs as of December 31, 2025. For more information regarding the plans, read Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Plan Category						(a) Number of  Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (1)						(b) Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights						(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (2)
Equity compensation plans approved by security holders						3,723,054						— (3)						12,392,987
Total						3,723,054						—						12,392,987

_________________________________________________________________________________________

(1)Includes performance units at their maximum payout of 200%.

(2)Includes the available units for issuance we assumed under the Aris Water Solutions Inc. 2021 Equity Incentive Plan upon our acquisition of Aris Water Solutions on October 15, 2025.

(3)Phantom and performance units constitute the only rights outstanding under the WES LTIPs. Each phantom or performance unit that may be settled in common units entitles the holder to receive, upon vesting and determination of any performance criteria, if applicable, one common unit with respect to each phantom or performance unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.

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

As of February 13, 2026, Occidental held (i) 150,374,176 of our common units, representing a 37.3% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.2% general partner interest in us, and (iii) a 1.9% limited partner interest in WES Operating through its ownership of WGRAH.

We control, manage, and operate WES Operating through our ownership of WES Operating GP. We, directly and indirectly through our ownership of WES Operating GP, owned a 98.1% limited partner interest and the entire non-economic general partner interest in WES Operating.

The officers of our general partner are also officers of WES Operating GP and our general partner’s officers operate WES Operating’s business. Other than our CEO, who serves as a director, three of our directors are currently affiliated with Occidental and our remaining three directors are independent as defined by the NYSE.

Agreements with Occidental

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

Summary of Material Related-Party Transactions

The following tables summarize material related-party transactions included in our consolidated financial statements (see Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K):

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—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2)Includes related-party natural-gas and NGLs imbalances.

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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—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2)Includes contract liabilities from contracts with customers. See Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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 our partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

(3)Represents common units repurchased from Occidental. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

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 us 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 us 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 us 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 us that were used to repurchase common units. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

Gathering and processing agreements. We have significant gathering, treating, processing, stabilization, and produced-water disposal arrangements with affiliates of Occidental on most of our systems. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. For the year ended December 31, 2025, excluding the impact of equity-investments, production owned or controlled by Occidental represented 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.

We have 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 our DJ Basin oil-gathering system. If such discussions are resolved in a manner adverse to us, such resolution could have a negative impact on our financial condition and results of operations, including a reduction in rates and a non-cash charge to earnings.

Marketing services. While we market and sell substantially all of our crude oil, residue gas, and NGLs directly to third parties, we 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.

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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 our 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 our and WES Operating’s agreements with Occidental. Cost of product expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and transactions with affiliates accounted for under the equity method of accounting. See Marketing 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 us and WES Operating pursuant to the agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP (“Services Agreement”). Most of the administrative and operational services previously provided by Occidental fully transitioned to us by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

Construction reimbursement agreements and purchases and sales with related parties. From time to time, we enter into construction reimbursement agreements with Occidental providing that we will manage the construction of certain midstream infrastructure for Occidental in our areas of operation. Such arrangements generally provide for a reimbursement of costs incurred by us on a cost or cost-plus basis.

Additionally, from time to time, in support of our business, we purchase and sell equipment, inventory, and other miscellaneous assets from or to Occidental or its affiliates.

Related-party commercial agreement. During the first quarter of 2021, an affiliate of Occidental and 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.

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Indemnification agreements with directors and officers. Our general partner has entered into indemnification agreements with each of its officers and directors (each, an “Indemnitee”). The indemnification agreements provide that each Indemnitee will be indemnified and held harmless against all expense, liability, and loss (including attorney’s fees, judgments, fines or penalties, and amounts to be paid in settlement) actually and reasonably incurred or suffered by the Indemnitee in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its Board to the fullest extent permitted by applicable law, including Section 18-108 of the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. The indemnification agreements also provide that advance payment of certain expenses must be made to the Indemnitee, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.

Through December 31, 2025, there have been no payments or claims to Occidental related to these indemnification agreements and no payments or claims have been received from Occidental related to these indemnification agreements.

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

•Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;

•Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and

•Chipeta’s membership interests are subject to significant restrictions on transfer.

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

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Review, Approval, or Ratification of Transactions with Related Persons

Our Audit Committee generally reviews transactions between WES and its directors, executive officers, or their immediate family members, or significant equity holders involving, in any case, amounts in excess of $120,000. However, our Board may also request that certain transactions between WES and Occidental, or our general partner, be reviewed by the Special Committee pursuant to our partnership agreement, as described in more detail below.

Whenever a conflict arises between our general partner or its related parties, including Occidental, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve the conflict. Our partnership agreement contains provisions that modify and limit our general partner’s default state law fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of fiduciary duties otherwise applicable under state law. See Special Committee under Part III, Item 10 of this Form 10-K.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is any of the following:

•approved by the Special Committee of our general partner, although our general partner is not obligated to seek such approval;

•approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but in most circumstances is not required to, seek the approval of such resolution from the Special Committee of its Board. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Special Committee and its Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, our general partner or the Special Committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. Our partnership agreement provides that for someone to act in good faith, that person must reasonably believe he is acting in the best interests of the Partnership.

Additionally, the Board has adopted a written Code of Ethics and Business Conduct (the “Code”), under which all directors and officers of the general partner, and employees working on our behalf, are expected to avoid conflicts or the appearance of conflicts in relation to their duties and responsibilities to us, and report any violation of the Code by any person. Under our Corporate Governance Guidelines, any waivers of the Code for any officer or director may only be made by the Board or by a committee of the Board composed of independent directors.

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Item 14. Principal Accounting Fees and Services

We have engaged KPMG LLP as our and WES Operating’s independent registered public accounting firm. The following table presents fees for the audit of the annual consolidated financial statements for the last two fiscal years and for other services provided by KPMG LLP:

						WES												WES Operating
thousands						2025						2024						2025						2024
Audit fees						$	520					$	625					$	3,115					$	2,831
Audit-related fees						—						—						—						175
Total						$	520					$	625					$	3,115					$	3,006

Audit fees are primarily for the audit of our and WES Operating’s consolidated financial statements, including the audit of the effectiveness of internal control over financial reporting, consents, comfort letters, other audits, and the reviews of financial statements included in the Forms 10-Q. Audit-related fees for the year ended December 31, 2024, include fees associated with reasonable assurance services related to certain metrics included in our 2023 Sustainability Report.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of our general partner has adopted a Pre-Approval Policy with respect to services that may be performed by KPMG LLP. This policy lists specific audit-related services and any other services that KPMG LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairperson, to whom such authority has been conditionally delegated, prior to engagement. During 2025, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee. During 2025, the Audit Committee reviewed and approved the use of KPMG LLP’s Accounting research and disclosure checklist applications for no additional fee.

The Audit Committee has approved the appointment of KPMG LLP as independent registered public accounting firm to conduct the audit of our and WES Operating’s consolidated financial statements for the year ended December 31, 2026.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

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

(a)(2) Financial Statement Schedules

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

(a)(3) Exhibits

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Exhibit Index

Exhibit Number												Description
#			2.			1						Contribution Agreement and Agreement and Plan of Merger, dated as of November 7, 2018, by and among Anadarko Petroleum Corporation, Anadarko E&P Onshore LLC, APC Midstream Holdings, LLC, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC, Western Gas Partners, LP, Western Gas Holdings, LLC, Clarity Merger Sub, LLC, WGR Asset Holding Company LLC, WGR Operating, LP, Kerr-McGee Gathering LLC, Kerr-McGee Worldwide Corporation and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 8, 2018, File No. 001-35753).
			2.			2						Agreement and Plan of Merger, dated as of August 6, 2025, by and among Western Midstream Partners, LP, Arrakis OpCo Merger Sub LLC, Arrakis Holdings Inc., Arrakis Unit Merger Sub LLC, Arrakis Cash Merger Sub LLC, Aris Water Solutions, Inc. and Aris Water Holdings, LLC (incorporated by reference to Exhibit 2.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on August 6, 2025, File No. 001-35753).
			3.			1						Certificate of Limited Partnership of Western Gas Equity Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Western Gas Equity Partners, LP filed on November 5, 2012, File No. 333-184763).
			3.			2						Certificate of Amendment to Certificate of Limited Partnership of Western Gas Equity Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
			3.			3						Second Amended and Restated Agreement of Limited Partnership of Western Midstream Partners, LP, dated as of December 31, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
			3.			4						Certificate of Formation of Western Gas Equity Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Equity Partners, LP’s Registration Statement on Form S-1 filed on November 5, 2012, File No. 333-184763).
			3.			5						Certificate of Amendment to Certificate of Formation of Western Gas Equity Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
			3.			6						Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.7 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
			3.			7						Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on March 26, 2019, File No. 001-35753).
			3.			8						Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
			3.			9						Fourth Amended and Restated Agreement of Limited Partnership of Western Midstream Operating, LP, dated as of October 15, 2025. (incorporated by reference to Exhibit 99.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on November 28, 2025, File No. 001-34046).
			3.			10						Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
			3.			11						Certificate of Amendment to Certificate of Formation of Western Gas Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
			3.			12						Third Amended and Restated Limited Liability Company Agreement of Western Midstream Operating GP, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.8 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).

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Exhibit Number												Description
			3.			13						Certificate of Merger of Clarity Merger Sub, LLC with and into Western Gas Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
			4.			1						Description of the registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.1 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024, File No. 001-35753).
			4.			2						Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
			4.			3						Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
			4.			4						Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
			4.			5						Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
			4.			6						Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
			4.			7						Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
			4.			8						Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
			4.			9						Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
			4.			10						Ninth Supplemental Indenture, dated as of March 2, 2018, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
			4.			11						Form of 4.500% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
			4.			12						Form of 5.300% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
			4.			13						Tenth Supplemental Indenture, dated as of August 9, 2018, by and between Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
			4.			14						Form of 4.750% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
			4.			15						Form of 5.500% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
			4.			16						Eleventh Supplemental Indenture, dated as of January 13, 2020, by and between Western Midstream Operating, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
			4.			17						Form of 3.100% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).

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Exhibit Number												Description
			4.			18						Form of 4.050% Senior Notes due 2030 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A-3 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
			4.			19						Form of 5.250% Senior Notes due 2050 (incorporated by reference to Exhibit 4.5, which is included as Exhibit A-4 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
			4.			20						Twelfth Supplemental Indenture, dated as of April 4, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on April 5, 2023, File No. 001-34046).
			4.			21						Form of 6.150% Senior Notes due 2033 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on April 5, 2023, File No. 001-34046).
			4.			22						Thirteenth Supplemental Indenture, dated as of September 29, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on September 29, 2023, File No. 001-34046).
			4.			23						Form of 6.350% Senior Notes due 2029 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on September 29, 2023, File No. 001-34046).
			4.			24						Fourteenth Supplemental Indenture, dated as of August 20, 2024, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on August 20, 2024, File No. 001-34046).
			4.			25						Form of 5.450% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on August 20, 2024, File No. 001-34046).
			4.			26						Fifteenth Supplemental Indenture, dated as of December 4, 2025, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee.(incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on December 4, 2025, File No. 001-34046).
			4.			27						Form of 4.800% Senior Notes due 2031 (included as Exhibit A-1 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on December 4, 2025, File No. 001-34046).
			4.			28						Form of 5.500% Senior Notes due 2035 (included as Exhibit A-2 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on December 4, 2025, File No. 001-34046).
			4.			29						Indenture, dated as of March 25, 2025, by and among Aris Water Holdings, LLC, the guarantors named therein and Computershare Trust Company, N.A., as trustee. (incorporated by reference to Exhibit 4.1 to Aris Water Solutions, Inc.’s Current Report on Form 8-K filed on March 25, 2025, File No. 001-40955).
			4.			30						Form of 7.250% Senior Notes due 2030 (included as Exhibit A in Exhibit 4.1 to Aris Water Solutions, Inc.’s Current Report on Form 8-K filed on March 25, 2025, File No. 001-40955).
			4.			31						Supplemental Indenture, dated as of October 15, 2025, by and among Western Midstream Operating, LP and Computershare Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on October 15, 2025, File No. 001-34046).
			10.			1						Amended and Restated Services, Secondment and Employee Transfer Agreement, by and between Occidental Petroleum Corporation, Anadarko Petroleum Corporation and Western Midstream Operating GP, LLC, dated as of December 31, 2019 (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
			10.			2						Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
			10.			3						Tax Sharing Agreement by and between Western Gas Equity Partners, LP and Anadarko Petroleum Corporation, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by Western Gas Equity Partners, LP on December 12, 2012, File No. 001-35753).
			10.			4						Form of Indemnification Agreement by and between Western Midstream Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.16 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).

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Exhibit Number												Description
			10.			5						Western Midstream Partners, LP Incentive Compensation Program (incorporated by reference to Exhibit 10.19 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 22, 2023, File No. 001-35753).
‡			10.			6						Western Midstream Partners, LP Executive Severance Plan (Amended and Restated as of February 20, 2025) (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 7, 2025, File No. 001-35753).
*‡			10.			7						Western Midstream Partners, LP Executive Change in Control Severance Plan (Amended and Restated as of February 12, 2026).
‡			10.			8						Western Gas Partners, LP 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 17, 2017, File No. 001-34046).
‡			10.			9						Western Midstream Partners, LP 2021 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on August 9, 2021, File No. 001-35753).
‡			10.			10						Form of Director Award Agreement (incorporated by reference to Exhibit 4.8 to Western Gas Partners, LP’s Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed on December 13, 2017, File No. 333-151317).
‡			10.			11						Form of 2023 Phantom Unit Award Agreement (TUR Awards) (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 3, 2023, File No. 001-35753).
‡			10.			12						Form of 2024 Phantom Unit Award Agreement (Time-Based Awards) (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 8, 2024, File No. 001-35753).
‡			10.			13						Form of 2024 Phantom Unit Award Agreement (TUR Awards) (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 8, 2024, File No. 001-35753).
‡			10.			14						Form of 2024 Phantom Unit Award Agreement (ROA Awards) (incorporated by reference to Exhibit 10.3 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 8, 2024, File No. 001-35753).
‡			10.			15						Transition and Separation Agreement and General Release entered into by and between Western Midstream Partners, LP and Michael P. Ure (incorporated by reference to Exhibit 10.16 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 26, 2025, File No. 001-35753).
‡			10.			16						Retirement Agreement, dated February 18, 2025, between Robert W. Bourne and Western Midstream Partners, LP (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 7, 2025, File No. 001-35753).
			10.			17						Fourth Amended and Restated Revolving Credit Agreement, dated as of April 6, 2023, among Western Midstream Operating, LP, as the Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on April 10, 2023, File No. 001-35753).
			10.			18						First Amendment to Fourth Amended and Restated Revolving Credit Agreement, dated as of May 16, 2024, among Western Midstream Operating, LP, as the Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on May 16, 2024, File No. 001-35753).
			10.			19						Form of Commercial Paper Dealer Agreement between WES Operating, as Issuer, and the Dealer party thereto, for the Commercial Paper Program (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on November 16, 2023, File No. 001-35753).
†			10.			20						Gas Gathering Agreement effective July 1, 2010 between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP, as amended by Amendment No. 1 dated August 4, 2011, Amendment No. 2 dated December 3, 2012, Amendment No. 3 dated November 19, 2013 and Amendment No. 4 dated June 2, 2014 (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 26, 2015, File No. 001-34046).
†			10.			21						Amendment to Gas Gathering Agreement effective August 1, 2017, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on July 26, 2017, File No. 001-34046).

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Exhibit Number												Description
†			10.			22						Amendment to Gas Gathering Agreement effective January 1, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.29 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
†			10.			23						Amendment to Gas Gathering Agreement, dated May 10, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2018, File No. 001-34046).
†			10.			24						Amendment to Gas Gathering Agreement effective January 1, 2020, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.42 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).
†			10.			25						Amendment to Gas Gathering Agreement, dated effective September 30, 2024, between WES DJ Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.28 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 26, 2025, File No. 001-35753).
†			10.			26						Gas Gathering Agreement between Anadarko E&P Onshore LLC and Delaware Basin Midstream, LLC, dated October 8, 2018 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on October 31, 2018, File No. 001-34046).
†			10.			27						Second Amendment to Gas Gathering Agreement by and between Delaware Basin Midstream LLC and Anadarko E&P Onshore LLC, effective as of the May 1, 2023 (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on August 8, 2023, File No. 001-35753).
†			10.			28						Third Amendment to Gas Gathering Agreement by and between Delaware Basin Midstream LLC and Anadarko E&P Onshore LLC, dated January 16, 2026 (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-Q filed on January 22, 2026, File No. 001-35753).
			19.			1						WES Insider Trading Policy (incorporated by reference to Exhibit 19.1 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 26, 2025, File No. 001-35753).
*			21.			1						List of Subsidiaries of Western Midstream Partners, LP.
*			23.			1						Consent of KPMG LLP - Western Midstream Partners, LP.
*			23.			2						Consent of KPMG LLP - Western Midstream Operating, LP.
			24.			1						Power of Attorney (included on the signatures page of this annual report on Form 10-K).

184

Table of Contents

Exhibit Number

Description

*

31.

1

Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.

*

31.

2

Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.

*

31.

3

Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.

*

31.

4

Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.

**

32.

1

Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.

**

32.

2

Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.

‡

97.

1

Western Midstream Partners, LP Incentive Policy on Recoupment of Incentive Compensation (incorporated by reference to Exhibit 97.1 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024, File No. 001-35753).

*

101.

INS

XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)

*

101.

SCH

Inline XBRL Schema Document

*

101.

CAL

Inline XBRL Calculation Linkbase Document

*

101.

DEF

Inline XBRL Definition Linkbase Document

*

101.

LAB

Inline XBRL Label Linkbase Document

*

101.

PRE

Inline XBRL Presentation Linkbase Document

*

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

______________________________________________________________________________________

*			Filed herewith
**			Furnished herewith
#			Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
†			Portions of this exhibit have been omitted as confidential pursuant to Item 601(b)(10) of Regulation S-K or a request for confidential treatment.
‡			Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

Item 16. Form 10-K Summary

    Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

WESTERN MIDSTREAM PARTNERS, LP

February 18, 2026

/s/ Oscar K. Brown

Oscar K. Brown

President and Chief Executive Officer

Western Midstream Holdings, LLC

(as general partner of Western Midstream Partners, LP)

February 18, 2026

/s/ Kristen S. Shults

Kristen S. Shults

Senior Vice President and Chief Financial Officer

Western Midstream Holdings, LLC

(as general partner of Western Midstream Partners, LP)

WESTERN MIDSTREAM OPERATING, LP

February 18, 2026

/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)

February 18, 2026

/s/ Kristen S. Shults

Kristen S. Shults

Senior Vice President and Chief Financial Officer

Western Midstream Operating GP, LLC

(as general partner of Western Midstream Operating, LP)

Each person whose signature appears below constitutes and appoints Oscar K. Brown and Kristen S. Shults, and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.

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Table of Contents

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following officers in their capacities at Western Midstream Holdings, LLC, the general partner of Western Midstream Partners, LP, and Western Midstream Operating GP, LLC, the general partner of Western Midstream Operating, LP, and the following directors in their capacities at Western Midstream Holdings, LLC, the general partner of Western Midstream Partners, LP which is the sole member of Western Midstream Operating GP, LLC, the general partner of Western Midstream Operating, LP, on February 18, 2026.

Signature			Title (Position with Western Midstream Holdings, LLC and Western Midstream Operating GP, LLC, as applicable)
/s/ Peter J. Bennett			Chair
Peter J. Bennett
/s/ Oscar K. Brown			President, Chief Executive Officer and Director
Oscar K. Brown			(Principal Executive Officer)
/s/ Kristen S. Shults			Senior Vice President and Chief Financial Officer
Kristen S. Shults			(Principal Financial Officer)
/s/ Catherine A. Green			Senior Vice President and Chief Accounting Officer
Catherine A. Green			(Principal Accounting Officer)
/s/ Nicole E. Clark			Director
Nicole E. Clark
/s/ Frederick A. Forthuber			Director
Frederick A. Forthuber
/s/ Kenneth F. Owen			Director
Kenneth F. Owen
/s/ Robert G. Phillips			Director
Robert G. Phillips
/s/ David J. Schulte			Director
David J. Schulte
/s/ Lisa A. Stewart			Director
Lisa A. Stewart

187

FAQ

What is Western Midstream Partners (WES) main business according to this 10-K?

Western Midstream Partners focuses on 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 across Texas, New Mexico, and the Rocky Mountain region.

How large is Western Midstream Partners’ asset base as of December 31, 2025?

As of December 31, 2025, Western Midstream operated 14,910 miles of pipeline with 5,780 MMcf/d of gas processing and treating capacity and 6,304 MBbls/d of liquids and produced-water capacity, reflecting a large, geographically diverse midstream network across Texas, New Mexico, Colorado, Utah, and Wyoming.

What were the key terms of Western Midstream’s acquisition of Aris Water Solutions?

Western Midstream completed a $2.0 billion Aris acquisition, including cash and equity consideration, repayment of $80.0 million of Aris revolver borrowings, and $500.0 million of senior notes. It issued 26.6 million common units and paid $415.0 million in cash, adding extensive produced-water and recycling infrastructure.

How dependent is Western Midstream Partners on Occidental Petroleum for revenue?

For the year ended December 31, 2025, Occidental’s production accounted for 60% of total revenues (excluding equity investments), 91% of crude-oil and NGLs throughput, and 61% of produced-water throughput, making Occidental Western Midstream’s largest and most critical customer relationship.

What is Western Midstream Partners’ 2025 Purchase Program?

The 2025 Purchase Program authorizes up to $250.0 million of common unit repurchases through December 31, 2026. Units may be bought in the open market at prevailing prices or via privately negotiated transactions, supporting Western Midstream’s objective of increasing capital returns to stakeholders.

What major growth projects does Western Midstream highlight in this filing?

Western Midstream is building North Loving Train II, a 300 MMcf/d cryogenic processing train expected in second quarter 2027, and the Pathfinder produced-water project, including a 42‑mile, 30‑inch pipeline able to transport over 800 MBbls/d and three clean‑water facilities totaling about 280 MBbls/d capacity.

How does Western Midstream mitigate commodity price and volume risk?

Western Midstream emphasizes fee-based contracts with protections like minimum-volume commitments and cost-of-service structures. In 2025, 97% of wellhead gas volume and 100% of crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based arrangements, supporting more stable cash flows across commodity cycles.