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, ~~2024~~2025


☐			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

Western Midstream Operating, LP

Yes

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

Western Midstream Operating, LP

Yes

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

Western Midstream Operating, LP

Yes

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

Western Midstream Operating, LP

Yes

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

☐

Western Midstream Operating, LP

Large Accelerated Filer

Accelerated Filer

Non-accelerated Filer

Smaller Reporting Company

Emerging Growth Company

☐

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

☐

Western Midstream Operating, LP

Yes

☐

The aggregate market value of the registrant’s common units representing limited partner interests held by non-affiliates of the registrant on June 30, ~~2024~~2025, based on the closing price as reported on the New York Stock Exchange.

Western Midstream Partners, LP			$78.73 billion
Western Midstream Operating, LP			None

Common units outstanding as of February 2113, ~~2025~~2026:

Western Midstream Partners, LP			~~381~~393,~~321~~667,~~137~~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	2526
	Regulation of Operations	26
	Environmental Matters and Occupational Health and Safety Regulations	2928
	Title to Properties and Rights-of-Way	3432
	Human Capital Resources	3432
1A.	Risk Factors	3533
1B.	Unresolved Staff Comments	5049
1C.	Cybersecurity	5149
3.	Legal Proceedings	5149
4.	Mine Safety Disclosures	5149
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	5250
	Market Information	5250
	Other Securities Matters	5250
	Selected Information From Our Partnership Agreement	5351
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5452
	Executive Summary	5452
	Our Operations	5654
	How We Evaluate Our Operations	5654
	Items Affecting the Comparability of Our Financial Results	5755
	Results of Operations	5855
	Operating Results	5856
	Reconciliation of Non-GAAP Financial Measures	6562
	Key Performance Metrics	7066
	General Trends and Outlook	7166
	Liquidity and Capital Resources	7368
	Items Affecting the Comparability of Financial Results with WES Operating	7872
	Critical Accounting Estimates	7974
	Recent Accounting Developments	8075
7A.	Quantitative and Qualitative Disclosures About Market Risk	8176
8.	Financial Statements	8277
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~135~~133
9A.	Controls and Procedures	~~135~~133
9B.	Other Information	~~135~~133
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	~~136~~134

Item		Page
	PART III
10.	Directors, Executive Officers, and Corporate Governance	136
11.	Executive Compensation	143
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	172
13.	Certain Relationships and Related Transactions, and Director Independence	174
14.	Principal Accounting Fees and Services	180
	PART IV
15.	Exhibits, Financial Statement Schedules	180
16.	Form 10-K Summary	185

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

Table of Contents

COMMONLY USED ABBREVIATIONS AND TERMS

References to “we,” “us,” “our,” “WES,” “the Partnership,” or “Western Midstream Partners, LP” refer to Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) and its subsidiaries. The following list of abbreviations and terms are used in this document:

			Defined Term						Definition
			Anadarko						Anadarko Petroleum Corporation and its subsidiaries, excluding our general partner, which became a wholly owned subsidiary of Occidental upon closing of the Occidental Merger on August 8, 2019.
			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.
			Cactus II						Cactus II Pipeline LLC, in which we held a 15% interest that we sold in November 2022 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			Chipeta						Chipeta Processing, LLC, in which we are the managing member 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.
			Floating-Rate Senior Notes due 2023						WES Operating’s floating-rate Senior Notes due 2023, which were fully repaid in January 2023.
			FERC						The Federal Energy Regulatory Commission.
			FRP						Front Range Pipeline LLC, in which we own a 33.33% interest.
			GAAP						Generally accepted accounting principles in the United States.
			General partner						Western Midstream Holdings, LLC, the general partner of the Partnership.
			Imbalance						Imbalances result from (i) differences between gas and NGLs volumes nominated by customers and gas and NGLs volumes received from those customers and (ii) differences between gas and NGLs volumes received from customers and gas and NGLs volumes delivered to those customers.
			Marcellus Interest						The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania 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.
			NYSE						New York Stock Exchange.

			Defined Term						Definition
			Occidental						Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner.
			Occidental Merger						Occidental’s acquisition by merger of Anadarko pursuant to the Occidental Merger Agreement, which closed on August 8, 2019.
			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.
			Ranch Westex						Ranch Westex JV LLC, in which we owned a 50% interest through August 2022, and a 100% interest thereafter (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			RCF						WES Operating’s $2.0 billion senior unsecured revolving credit facility.
			Red Bluff Express						Red Bluff Express Pipeline, LLC, in which we own a 30% interest.
			Red Desert complex						The Red Desert gathering lines and related facilities.
			Related parties						Occidental, the Partnership’s equity interests (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), and the Partnership and WES Operating for transactions that eliminate upon consolidation.
			Rendezvous						Rendezvous Gas Services, LLC, in which we own a 22% interest.
			Residue						The natural gas remaining after the unprocessed natural-gas stream has been processed or treated.
			Saddlehorn						Saddlehorn Pipeline Company, LLC, in which we 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, by and among Occidental, Anadarko, and WES Operating GP.
			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.
			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.
			$1.25 billion Purchase Program						The $1.25 billion buyback program that ended 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.

Table of Contents


			Defined Term						Definition
			NYSE						New York Stock Exchange.
			Occidental						Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner.

			OTTCO						Overland Trail Transmission, LLC.
			Panola						Panola Pipeline Company, LLC, in which we owned a 15% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			Powder River Basin complex						The Hilight system and assets acquired from Meritage, which includes a gathering system, processing plants, and the Thunder Creek NGL pipeline (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			Produced water						Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.

			RCF						WES Operating’s $2.0 billion senior unsecured revolving credit facility.
			Recycled water						Water from industrial processes, such as produced water from wells or flowback from hydraulic fracturing, which has been treated to a standard suitable for reuse in other operations.
			Red Bluff Express						Red Bluff Express Pipeline, LLC, in which we own a 30% interest.
			Red Desert complex						The Red Desert gathering lines and related facilities.
			Related parties						Occidental, the Partnership’s equity interests (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), and the Partnership and WES Operating for transactions that eliminate upon consolidation.
			Rendezvous						Rendezvous Gas Services, LLC, in which we own a 22% interest.
			Residue						The natural gas remaining after the unprocessed natural-gas stream has been processed or treated.
			Saddlehorn						Saddlehorn Pipeline Company, LLC, in which we owned a 20% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			SEC						U.S. Securities and Exchange Commission.
			Services Agreement						That certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, between WES Operating GP and Occidental.
			Skim oil						A crude-oil byproduct that is recovered during the produced-water gathering and disposal process.
			Springfield system						The Springfield gas-gathering system and Springfield oil-gathering system.
			Stabilization						The process to reduce the volatility of a liquid hydrocarbon stream by separating very light hydrocarbon gases, methane and ethane in particular, from heavier hydrocarbon components. This process reduces the volatility of the liquids during transportation and storage.
			Tailgate						The point at which processed natural gas and/or natural-gas liquids leave a processing facility for end-use markets.
			TEG						Texas Express Gathering LLC, in which we own a 20% interest.
			TEP						Texas Express Pipeline LLC, in which we own a 20% interest.
			Water solutions volumes						Water solutions volumes include groundwater and gathered produced water that is treated and recycled.
			WES Operating						Western Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries.
			WES Operating GP						Western Midstream Operating GP, LLC, the general partner of WES Operating.
			West Texas complex						The Delaware Basin Midstream complex and DBJV and Haley systems.
			WGRAH						WGR Asset Holding Company LLC, a subsidiary of Occidental.
			White Cliffs						White Cliffs Pipeline, LLC, in which we own a 10% interest.
			Whitethorn LLC						Whitethorn Pipeline Company LLC, in which we owned a 20% interest that we sold in February 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
			Whitethorn						A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC.
			2025 Purchase Program						The $250.0 million buyback program ending December 31, 2026. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.

Table of Contents

PART I1

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 98.01% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of WES Operating GP, which holds the entire non-economic general partner interest in WES Operating.

WES’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our ~~98.0%~~ partnership interest in WES Operating, ~~as of December 31, 2024~~ (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 ~~natural gas~~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 ~~disposal~~our integrated network of facilities that (i) remove hydrocarbon products and other sediments from ~~the~~ produced water, (ii) recycle and ~~re-inject~~supply ~~the~~treated produced water ~~utilizing~~and ~~permitted~~groundwater ~~disposal~~for ~~wells~~use in ~~compliance~~our ~~with~~customers’ ~~applicable~~operations, ~~regulations~~and or (iiiii) ~~sell~~re-inject ~~the~~ produced water toutilizing ~~third~~permitted ~~parties~~disposal ~~to be treated and recycled~~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.

Table of Contents

ASSETS AND AREAS OF OPERATION

Table of Contents

As of December 31, ~~2024~~2025, our assets and investments consisted of the following:

	WhollyOwned andOperated	OperatedInterests	EquityInterests
Gathering systems (1)	18	2	1
Gathering systems	13	2	1
Treating facilities	4243	3	—
Natural-gas processing plants/trains	26	3	1
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.

~~These~~(2)Includes ~~assets~~throughput ~~and~~for ~~investments~~all ~~are~~assets ~~located~~owned ~~in Texas, New Mexico,~~ and ~~the~~ownership ~~Rocky~~interests ~~Mountains~~accounted ~~(Colorado,~~for ~~Utah,~~by ~~and~~us ~~Wyoming).~~under ~~The~~the ~~following~~equity ~~table~~method ~~provides information regarding our assets by geographic region, as~~ of ~~and~~accounting. ~~for~~For ~~the~~further ~~year~~details ~~ended~~see ~~December~~Properties ~~31, 2024:~~below.

Area	Asset Type	Miles of Pipeline (1)	Compression (1) (2)			Processing or Treating Capacity (MMcf/d) (1)	Processing, Treating, or Disposal Capacity (MBbls/d) (1)	Average Throughput for Natural-Gas Assets(MMcf/d) (3)	Average Throughput for Crude-Oil and NGLs Assets (MBbls/d) (3)	Average Throughput for Produced-Water Assets(MBbls/d) (3)
			Horsepower	% Electric Driven
Texas / New Mexico	Gathering, Processing, Treating, and Disposal	4,410	1,004,691	32	%	2,370	2,540	2,322	267	1,147
	Transportation	1,272	—	—		—	—	387	122	—
Rocky Mountains	Gathering, Processing, and Treating	7,126	689,422	41	%	3,160	232	2,370	92	—
	Transportation	1,563	—	—		—	—	109	60	—
North-central Pennsylvania	Gathering (4)	—	—	—		—	—	38	—	—
Total		14,371	1,694,113	35	%	5,530	2,772	5,226	541	1,147

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.

_________________________________________________________________________________________

(1)All system metrics are presented on a gross basis and include owned and leased compressors at certain facilities. Includes horsepower associated with liquid pump stations. Includes bypass capacity at the DJ Basin and West Texas complexes.

(2)Excludes compression horsepower for transportation.

(3)Includes throughput for all assets owned and ownership interests accounted for by us under the equity method of accounting. For further details see Properties below.

(4)We closed on the sale of our 33.75% interest in the Marcellus Interest systems during 2024. See Acquisitions and Divestitures within these Items 1 and 2 for additional information.

Our operations are organized into a single operating segment that engages in gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. See Part II, Item 8 of this Form 10-K for disclosure of revenues and operating income (loss) for the years ended December 31, 2024, 2023, and 2022, and total assets for the years ended December 31, 2024 and 2023.

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ACQUISITIONS AND DIVESTITURES

~~Marcellus Interest systems.~~ During the ~~second~~fourth quarter of ~~2024~~2025, we closed on the ~~sale~~acquisition of ~~our~~Aris ~~33.75%~~by ~~interest~~merger in a transaction valued at $2.0 billion, including the ~~Marcellus~~cash ~~Interest~~and ~~systems~~equity ~~for~~merger ~~proceeds~~consideration, Aris’s outstanding debt of $~~206~~80.20 million in revolving credit facility borrowings that were repaid at closing, ~~resulting~~and $500.0 million in aprincipal ~~net~~amount ~~gain~~of senior notes. Based on ~~sale~~Aris ofshareholder consideration elections, we issued 26.6 million common units and paid $63415.90 million ~~that~~in ~~was~~cash, ~~recorded~~funded aswith ~~Gain~~borrowings ~~(loss)~~under onthe ~~divestiture~~commercial paper program, in exchange for all issued and ~~other~~outstanding shares of Aris common stock. Aris’s water infrastructure assets, ~~net~~located in ~~the~~Lea ~~consolidated~~and ~~statement~~Eddy Counties, New Mexico and West Texas, include approximately 830 miles of ~~operations~~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.

~~Mont~~During ~~Belvieu~~the ~~JV,~~second ~~Whitethorn~~quarter ~~LLC,~~of ~~Panola~~2024, ~~and~~we ~~Saddlehorn~~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. 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. The sale of the interests in Mont Belvieu JV and Whitethorn LLC also resolved outstanding legal proceedings associated with those assets.

~~Meritage.~~See InNote 3—Acquisitions ~~October~~and ~~2023~~Divestitures, weNote 5—Equity ~~closed~~and onPartners’ ~~the~~Capital, ~~acquisition~~and ofNote 13—Debt ~~Meritage~~in ~~for~~the ~~$885.0 million~~Notes ~~(subject~~ to ~~certain~~Consolidated ~~customary~~Financial ~~post-closing~~Statements ~~adjustments)~~under ~~funded with cash~~Part II, ~~including proceeds from our $600.0~~Item ~~million~~8 ~~senior~~of ~~note~~this ~~issuance~~Form ~~in September 2023 and borrowings on the RCF~~10-K.

See Note 3—Acquisitions and Divestitures and Note 13—Debt and Interest Expense 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 ~~and cost-of-service provisions~~.

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COMPETITIVE STRENGTHS

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

•Substantial presence in basins with historically strong producer economics. Our core operating areas are in the Delaware, DJ, and Powder River Basins, which historically have seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas are capable of servicing hydrocarbon production that contains natural gas, crude oil, condensate, and NGLs. Our systems in the Delaware Basin also include significant produced-water ~~takeaway~~gathering, ~~capacity~~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, as2025, 95and excluding the impact of equity investments, 97% of our wellhead natural-gas volume ~~(excluding equity investments)~~ and 100% of our crude-oil and produced-water throughput ~~(excluding equity investments)~~ were serviced under fee-based contracts ~~for the year ended December 31, 2024~~. 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 ~~mitigate~~have historically mitigated volumetric risk through minimum-volume commitments and cost-of-service contract structures. For the year ended December 31, ~~2024~~2025, and excluding the impact of equity investments, we had approximately 2.85 Bcf/d for our natural-gas assets ~~(excluding equity investments)~~, approximately ~~495~~476 MBbls/d for our crude-oil and NGLs assets ~~(excluding equity investments)~~, and approximately ~~965~~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.

•Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-dated debt maturity profile, long-term relationships, and reasonable access to capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital-market cycles. As of December 31, 2024, there was $2.0 billion in effective borrowing capacity under the RCF. 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.

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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.

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.

As of December 31, 2024, Occidental held (i) 165,681,578 of our common units, representing a 42.5% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.3% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGRAH, which is reflected as a noncontrolling interest within our consolidated financial statements. As of December 31, 2024, Occidental held 43.5% of our outstanding common units.

For the year ended December 31, 2024, 60% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 91% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts.

We have some marketing agreements with affiliates of Occidental; however, on January 1, 2021, we began marketing and selling substantially all our crude oil and residue gas, and a majority of our NGLs, directly to third parties.

Pursuant to the Services Agreement entered into on December 31, 2019, Occidental performed certain centralized corporate functions for the Partnership and WES Operating. Most of the administrative and operational services previously provided by Occidental fully transitioned to the Partnership by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

Although we believe our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business, it is also a source of potential conflicts. For example, Occidental is not restricted from competing with us. See Risk Factors under Part I, Item 1A and Certain Relationships and Related Transactions, and Director Independence under Part III, Item 13 of this Form 10-K for more information.

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PROPERTIES

The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, ~~2024~~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)	~~Compression~~Gathering ~~Horsepower (2)~~Systems	~~Gathering~~Pipeline ~~Systems~~Miles (2)	~~Pipeline Miles (3)~~
West Texas / New Mexico	West Texas complex (43)	Gathering, Processing, & Treating	1719	12,~~940~~190	6065	~~712,974~~3	31,920	~~1,974~~
West Texas	DBM oil system (54)	Gathering & Treating	19	—	~~355~~350	~~15,348~~1	1674	~~693~~
West Texas	DBM water systems	Gathering & Disposal	—	—	2,035	108,535	5	830
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	—	~~20,000~~—	—	—
South Texas	Brasada complex	Gathering, Processing, & Treating	3	230	15	~~29,400~~1	158	58
South Texas	Springfield system (7)	Gathering & Treating	3	—	75	~~118,434~~2	2852	~~855~~
Total			4345	2,~~370~~620	26,~~540~~072	~~1,004,691~~15	125,141	~~4,410~~

_________________________________________________________________________________________

(1)Includes 215 MMcf/d of bypass capacity at the West Texas complex.

(2)Includes ~~owned~~19 ~~and~~miles ~~leased~~of ~~compressors~~transportation related to the residue lines (regulated by FERC) at the West Texas complex and ~~compression~~15 ~~horsepower.~~miles ~~Includes~~of ~~horsepower~~transportation ~~associated~~related ~~with~~to ~~liquid~~a ~~pump~~crude-oil ~~stations~~pipeline at the DBM oil system.

(3)~~Includes~~The ~~19 miles of transportation related to the residue lines (regulated by FERC) at the~~ West Texas complex ~~and~~includes 15the ~~miles~~DBM ofcomplex, ~~transportation~~DBJV ~~related~~and toHaley asystems, ~~crude-oil~~and ~~pipeline at~~ the ~~DBM~~Ranch ~~oil~~Westex ~~system~~processing plant.

(4)The ~~West~~DBM ~~Texas~~oil ~~complex~~system includes ~~the~~five ~~DBM~~central ~~complex~~production facilities, ~~DBJV~~two ~~and~~regional ~~Haley~~oil ~~systems~~treating facilities, and ~~the~~three ~~Ranch~~combined ~~Westex~~oil ~~processing~~transfer/treating ~~plant~~facilities.

(5)The DBM ~~oil~~water ~~system~~systems ~~includes~~include ~~three~~assets ~~central~~acquired ~~production~~from ~~facilities, two regional oil treating facilities, and three combined oil transfer/treating facilities~~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, ~~2024~~2025, the ~~Mentone~~North ~~Train~~Loving ~~III processing~~ plant was completed, adding ~~300~~250 MMcf/d of processing capacity to the complex. ~~We also brought additional compressors online, adding approximately 76,000 compression horsepower to the complex.~~

•Customers. For the year ended December 31, ~~2024~~2025, Occidental’s production represented 43% of the West Texas complex throughput, and the two largest third-party customers provided 2829% of the throughput.

•Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring, Wolfcamp, and Penn formations in the Delaware Basin portion of the Permian Basin.

•Delivery points. Gas is dehydrated, compressed, and delivered to the Mi Vida plant (see below) and within the West Texas complex for processing, while lean gas is delivered into Enterprise GC, L.P.’s pipeline for ultimate delivery into Energy Transfer LP’s (“ET”) Oasis pipeline (the “Oasis pipeline”). Residue gas from the West Texas complex is delivered to the Red Bluff Express pipeline, Whitewater Midstream, LLC’s Agua Blanca pipeline, Oasis pipeline, Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”), and Kinder Morgan, Inc.’s interstate

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~~pipeline system~~•Supply. Supply of gas and NGLs ~~production~~for isthe ~~primarily~~complex ~~delivered~~comes ~~into~~from production from the ~~Sand~~Delaware ~~Hills~~Sands, ~~pipeline~~Avalon Shale, Bone Spring, Wolfcamp, and ~~Lone~~Penn ~~Star~~formations ~~NGL~~in ~~LLC’s~~the ~~pipeline~~Delaware ~~(“Lone~~Basin ~~Star~~portion ~~pipeline”).~~of the Permian Basin.

•~~North~~Delivery ~~Loving Plant~~points. WeGas ~~are~~is ~~currently~~dehydrated, ~~constructing~~compressed, aand ~~new~~delivered ~~cryogenic~~within ~~processing~~the West Texas complex and to the Mi Vida plant in(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 ~~North~~“Oasis ~~Loving~~pipeline”). ~~area~~Residue ofgas ~~our~~from the West Texas complex. ~~The~~is ~~North~~delivered ~~Loving~~to ~~Plant~~the ~~will~~Red ~~have~~Bluff aExpress ~~capacity~~pipeline, ofWhitewater ~~250~~Midstream, ~~MMcf/d~~LLC’s ~~and~~Agua isBlanca ~~expected~~pipeline, toOasis bepipeline, ~~completed~~Transwestern inPipeline ~~the~~Company ~~first~~LLC’s ~~quarter~~pipeline of(“Transwestern ~~2025.~~pipeline”), ~~Upon~~and ~~completion~~Kinder Morgan, Inc.’s interstate pipeline system. NGLs production is primarily delivered into the ~~West~~Sand ~~Texas~~Hills ~~complex~~pipeline, ~~will~~Lone ~~have~~Star aNGL ~~total~~LLC’s ~~processing~~pipeline ~~capacity~~(“Lone ofStar 2pipeline”),~~190~~ ~~MMcf/d~~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

~~During~~•Customers. ~~the~~As ~~year~~of ~~ended~~ December 31, ~~2024~~2025, weDBM ~~brought~~oil ~~three~~system ~~oil-treating~~throughput ~~facilities~~was ~~online,~~from ~~adding~~Occidental aand ~~total~~one ofthird-party 45producer. ~~MBbls/d~~For ofthe ~~treating~~year ~~capacity~~ended toDecember ~~the~~31, ~~system.~~2025, WeOccidental’s ~~also~~production ~~brought~~represented ~~additional~~99% ~~compressors~~of ~~online,~~the ~~adding~~total ~~approximately~~DBM ~~3,000~~oil ~~compression~~system ~~horsepower~~throughput and is subject to the ~~system~~Texas Railroad Commission tariff.

•Customers. As of December 31, 2024, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2024, 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 ~~disposal~~ systems

During the year ended December 31, ~~2024~~2025, wethe ~~brought~~Partnership ~~several~~completed ~~produced-water~~the ~~disposal~~Aris ~~wells~~acquisition ~~online,~~(see ~~adding~~Acquisitions aand ~~total~~Divestitures ofwithin ~~210~~these ~~MBbls/d~~Items of1 ~~disposal~~and ~~capacity~~2 tofor ~~the systems. We also brought~~ additional ~~pumps online, adding approximately 13,000 horsepower to the systems~~information).

•Customers. As of December 31, ~~2024~~2025, DBM water systems throughput was from Occidental and numerous third-party producers, with Occidental’s production representing 7861% 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.

•In January 2025, we sanctioned the construction of (i) a 42-mile, 30-inch pipeline with the capacity to transport over 800 MBbls/day of produced water to additional disposal facilities in eastern Loving County within the Delaware Basin, (ii) several regional produced-water gathering facilities and export terminals with total incremental capacity of approximately 280 MBbls/d, and (iii) nine incremental produced-water disposal facilities located in eastern Loving County with effective disposal capacity of approximately 220 MBbls/d. Construction is expected to be completed by the first quarter of 2027.16

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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, ~~2024~~2025, Mi Vida plant throughput was from ~~Occidental~~multiple ~~and one~~ third-party ~~customer~~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 ~~will~~provided ~~provide~~ 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, ~~2024~~2025, Brasada complex throughput was from ~~two~~one third-party ~~customers~~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, ~~2024~~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)

~~Compression~~Gathering ~~Horsepower~~Systems

~~Gathering~~Pipeline ~~Systems~~Miles (2)

~~Pipeline Miles (2)~~

Colorado

DJ Basin complex (3)

Gathering, Processing, & Treating

1,750

~~354,444~~2

21,677

~~1,742~~

Colorado

DJ Basin oil system

Gathering & Treating

—

155

~~6,545~~1

1462

~~470~~

Utah

Chipeta (4)

Processing

790

—

~~76,125~~—

—4

Total

2,540

225

~~437,114~~3

32,143

~~2,214~~

_________________________________________________________________________________________

(1)Includes ~~200~~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, ~~2024~~2025, Occidental’s production represented 5456% of the DJ Basin complex throughput, and the two largest third-party customers provided 3230% of the throughput.

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

•Delivery points. As of December 31, ~~2024~~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 ~~provides~~provide access to local NGLs markets.

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

•Customers. As of December 31, ~~2024~~2025, DJ Basin oil system throughput was from Occidental and ~~one~~two third-party ~~producer~~producers. For the year ended December 31, ~~2024~~2025, Occidental’s production represented 9998% 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.

1920

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Utah

Chipeta processing complex

~~•Customers.~~During ~~For~~ the year ended December 31, ~~2024~~2025, Chipeta ~~complex~~completed ~~throughput~~interconnect ~~was~~facilities ~~from~~to ~~numerous~~accommodate ~~third-party~~up ~~customers,~~to ~~with~~150 ~~the~~MMcf/d ~~four~~of ~~largest~~gas ~~customers~~receipts ~~providing~~from ~~88%~~Kinder ofMorgan’s ~~the~~Altamont ~~throughput~~Green River Pipeline.

•~~Supply~~Customers. ~~Chipeta’s~~For ~~inlet~~the isyear ~~connected~~ended ~~to Caerus Uinta LLC’s gathering system~~December 31, ~~the MountainWest Pipeline~~2025, ~~LLC~~Chipeta ~~system~~complex ~~(“MountainWest~~throughput ~~Pipeline”),~~was ~~and~~from ~~Three~~numerous ~~Rivers~~third-party ~~Gathering~~customers, ~~LLC’s~~with ~~system,~~the ~~which~~five islargest ~~owned~~customers byproviding ~~MPLX~~85% LPof ~~(“MPLX”)~~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.

•Expansion activity. In July 2024, additional compression installation was completed at the Chipeta complex, enabling the complex to receive up to 100 MMcf/d of incremental inlet gas via MountainWest Pipeline. We are in the process of installing new interconnect facilities at the Chipeta complex inlet, which will accommodate up to 150 MMcf/d of incremental gas and associated liquids via Kinder Morgan’s newly constructed Altamont Green River Pipeline, which is expected to be in service mid-2025. 21

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Overview - Rocky Mountains - Wyoming

Location

Asset

Type

Processing / Treating Plants

Processing / Treating Capacity (MMcf/d)

Processing / Treating Capacity (MBbls/d)

~~Compression~~Gathering ~~Horsepower~~Systems

~~Gathering~~Pipeline ~~Systems~~Miles (1)

~~Pipeline Miles (1)~~

Northeast Wyoming

Powder River Basin complex (2)

Gathering, Processing, & Treating

620

~~201,426~~2

2,685

~~2,767~~

Southwest Wyoming

Granger complex

Gathering

—

~~21,673~~1

1742

~~771~~

Southwest Wyoming

Red Desert complex

Gathering

—

~~20,809~~1

1,049

~~1,088~~

Southwest Wyoming

Rendezvous (3)

Gathering

—

~~8,400~~1

1286

~~286~~

Total

620

~~252,308~~5

54,762

~~4,912~~

_________________________________________________________________________________________

(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

~~The~~•Customers. ~~Powder~~For ~~River Basin complex includes~~ the ~~assets~~year ~~acquired~~ended ~~with~~December ~~the~~31, ~~closing~~2025, of the ~~Meritage~~three ~~acquisition~~largest inthird-party ~~October~~customers ~~2023,~~provided in66% ~~addition~~of tothe ~~our~~throughput, ~~legacy Hilight system. See Acquisitions~~ and ~~Divestitures~~Occidental’s ~~within~~production ~~these~~represented ~~Items~~3% 1of ~~and 2. During~~ the ~~year~~Powder ~~ended~~River ~~December~~Basin ~~31, 2024, we brought additional compressors online, adding approximately 5,000 compression horsepower to the~~ complex throughput.

•Customers. For the year ended December 31, 2024, the three largest third-party customers provided 67% of the throughput and Occidental’s production represented 4% 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

~~The~~•Customers. ~~Granger~~For ~~processing~~the ~~plant~~year ~~was~~ended ~~shut down in~~ December 31, ~~2023.~~2025, ~~The~~Granger ~~gathering~~complex ~~system~~throughput ~~continues~~was tofrom benumerous ~~operational~~third-party customers, ~~and~~with ~~gas gathered by~~ the ~~system~~two islargest ~~delivered~~customers toproviding a70% ~~third~~of ~~party~~the ~~for processing~~throughput.

•~~Customers~~Supply. ~~For~~The ~~the year ended December 31, 2024,~~ Granger complex ~~throughput~~is ~~was~~supplied ~~from~~by ~~numerous~~the ~~third-party~~Moxa ~~customers~~Arch, ~~with~~Jonah, ~~the~~and ~~three~~Pinedale ~~largest~~Anticline ~~customers providing 81% of the throughput~~fields.

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

•Delivery points. Residue gas from the Granger complex is delivered to a third party for processing and can then be delivered to the CIG pipeline; The Williams Companies, Inc.’s MountainWest Pipeline, Overthrust Pipeline, and Northwest Pipeline (“NWPL”); our OTTCO pipeline; and our Mountain Gas Transportation LLC pipeline. The NGLs have market access to the MAPL pipeline, which terminates at Mont Belvieu, Texas, and other local markets.

Red Desert gathering system

•Customers. For the year ended December 31, ~~2024~~2025, Red Desert complex throughput was from numerous third-party customers, with the three largest customers providing 5955% 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, ~~2024~~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 ~~MPLX~~Harvest Midstream’s Blacks Fork gas-processing plant, which connects to the MountainWest Pipeline, NWPL, and the Kern River pipeline via the Rendezvous pipeline.

2223

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TRANSPORTATION

2324

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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

Northeast Wyoming

MIGC (1)

Gas

100.00

243

Southwest Wyoming

OTTCO

Gas

100.00

~~221~~215

Colorado, Oklahoma, Texas

FRP (1) (2)

NGLs

33.33

~~435~~452

Texas

TEG (2)

NGLs

20.00

138

Texas

TEP (1) (2)

NGLs

20.00

~~579~~594

Texas

Red Bluff Express (1) (2)

Gas

30.00

~~120~~123

Total

2,~~835~~864

_________________________________________________________________________________________

(1)Regulated by FERC.

(2)Operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline. The White Cliffs dual pipeline system had multiple committed shippers, including Occidental, as of December 31, ~~2024~~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.

Rocky Mountains - Utah

GNB NGL pipeline. There were three primary shippers on the GNB NGL pipeline as of December 31, 2024. The GNB NGL pipeline provides capacity at the posted FERC-based rates and has the ability to receive NGLs from Chipeta’s gas-processing facility and MPLX’s Stagecoach/Iron Horse gas-processing complex. The GNB NGL pipeline delivers NGLs to the MAPL pipeline, which provides transportation through the Seminole pipeline and TEP’s pipeline, and ultimately to NGLs fractionation and storage facilities in Mont Belvieu, Texas.

Rocky Mountains - Wyoming

MIGC transportation system. For the year ended December 31, 2024, throughput on the MIGC system was from numerous third-party customers, with the three largest customers providing 83% of the system throughput. All parties on the MIGC system ship pursuant to a tariff on file with FERC. The system receives gas from the Hilight system, EOG’s Jewell plant, and from WBI Energy Transmission, Inc. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to interstate pipelines including the CIG pipeline, Tallgrass Interstate Gas Transmission pipeline, and WIC pipeline. Volumes can also be delivered to Black Hills Corporation’s Cheyenne Light Fuel & Power and several industrial users.

OTTCO transportation system. For the year ended December 31, 2024, throughput on the OTTCO transportation system was from three third-party shippers. Revenues on the system are generated from contracts that contain minimum-volume commitments and volumetric fees paid by shippers under firm and interruptible gas-transportation agreements. Supply points include the Granger complex, and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch, and the Jonah and Pinedale Anticline fields. Primary delivery points include two third-party industrial facilities.

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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, ~~2024~~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, ~~2024~~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, ~~2024~~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, ~~2024~~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. ~~In December 2020, WES entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline.~~ The pipeline is supplied by production from our West Texas complex and other third-party plants. The Red Bluff Express pipeline transports natural gas from Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas.

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 is greatest in areas experiencing heightened producer activity and during periods of high commodity prices. Notwithstanding, Occidental and third-party producers provide certain dedications and/or minimum-volume commitments in our significant areas of operation. We believe that our assets located outside of dedicated areas, whether in or out of the aforementioned significant areas of operation, are geographically well-positioned to retain and attract both Occidental and third-party volumes.

We believe the primary advantages of our assets include proximity to established and/or future production and the available service flexibility provided to producers. We believe we can efficiently, and at competitive and flexible contract terms, provide services that customers require to gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water.

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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.

REGULATION OF OPERATIONS

Pipeline Safety and Maintenance

Many of the pipelines we use to gather and transport oil, natural gas, and NGLs are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency under the U.S. Department of Transportation (“DOT”). Natural-gas pipelines are subject to PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”). Crude-oil and NGLs pipelines are ~~subject~~regulated toby 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

~~Regulation of pipeline-transportation services may affect certain aspects of our business and the market for our products and services.~~ The operations of our MIGC pipeline and the West Texas complex residue lines (exiting our Ramsey and Ranch Westex processing plants) are subject to regulation by FERC under the Natural Gas Act of 1938. FERC oversees various aspects of these assets’ operations, including rates, services, facility certification, capacity management, and market conduct.

26FERC-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.

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(the “NGA”). Under the NGA, FERC has authority to regulate natural-gas companies that provide natural-gas pipeline-transportation services in interstate commerce. Federal regulation extends to such matters as the following:

•rates, services, and terms and conditions of service;

•types of services that may be offered to customers;

•certification and construction of new facilities;

•acquisition, extension, disposition, or abandonment of facilities;

•maintenance of accounts and records;

•internet posting requirements for available capacity, discounts, and other matters;

•pipeline segmentation to allow multiple simultaneous shipments under the same contract;

•capacity release to create a secondary market for transportation services;

•relationships between affiliated companies involved in certain aspects of the natural-gas business;

•initiation and discontinuation of services;

•market manipulation in connection with interstate sales, purchases, or transportation of natural gas and NGLs; and

•participation by interstate pipelines in cash management arrangements.

Interstate natural-gas pipelines regulated by FERC also are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural-gas pipelines may interact with their marketing affiliates (unless FERC has granted a waiver of such standards). FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes. FERC’s market manipulation regulations make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. FERC and CFTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC and CFTC, we could be subject to substantial penalties and fines.

Interstate Liquids-Pipeline Regulation

~~Regulation~~Our of interstate liquids~~-pipeline~~ ~~services~~pipelines, ~~may~~including ~~affect certain aspects of our business and the market for our products and services. Our~~ GNB NGL, ~~and~~ Thunder Creek NGL ~~pipelines provide interstate service as a FERC-regulated common carrier under the Interstate Commerce Act~~, ~~the Energy Policy Act of 1992, and related rules and orders. We also own interests in~~ FRP, TEP, and White Cliffs, ~~each~~are ofregulated ~~which~~by ~~provides~~FERC ~~interstate services~~ as ~~a FERC-regulated~~ common ~~carrier~~carriers under ~~the~~federal ~~same statues and regulations~~law. FERC ~~regulation~~ requires that ~~interstate liquid-~~pipeline rates, ~~including rates for transportation of NGLs and crude oil,~~ be ~~filed with FERC and that these rates be~~ “just and reasonable” and ~~not~~uses ~~unduly discriminatory. Rates of interstate NGLs and crude-oil pipelines are currently regulated by FERC primarily through~~ an ~~annual~~ indexing methodology, ~~under~~reviewed ~~which pipelines increase or decrease rates in accordance with an index adjustment specified by FERC. The FERC’s indexing methodology is subject to review and revision~~ every five years, ~~with~~to ~~the~~adjust ~~most recent five-year review occurring in 2020~~rates. OnPipelines ~~December~~may ~~17,~~seek ~~2020,~~rate ~~FERC~~changes ~~established~~through ~~the index level for the five~~cost-~~year period commencing on July 1, 2021, which will end on June 30, 2026, at the Bureau~~ of ~~Labor’s producer~~-~~price~~service ~~index~~or ~~for finished goods (“PPI~~market-~~FG”)~~based ~~plus 0.78%. On January 20~~approaches, ~~2022, the FERC granted rehearing of certain aspects of the final rule~~ and ~~revised~~rates ~~the~~can ~~index~~be ~~level~~challenged toor ~~PPI-FG~~suspended ~~minus~~pending 0investigation.~~21%,~~ ~~effective March 1, 2022, through June 30, 2026.~~ FERC’s ~~ordered~~Revised ~~pipelines~~Policy ~~with~~Statement ~~filed~~restricts ~~rates~~MLPs ~~that~~from ~~exceed~~recovering ~~their~~income ~~index~~tax ~~ceiling levels based on PPI-FG minus 0.21% to file rate reductions effective March 1~~allowances, ~~2022.~~potentially ~~Following~~impacting ~~a decision of the appellate court issued on July 26, 2024, FERC reinstated the previous index level of PPI-FG plus 0~~revenues.~~78%~~ onThe aCFTC ~~prospective~~and ~~basis. An indexed rate is subject to challenge if~~ the ~~increase~~Federal isTrade ~~substantially~~Commission inalso ~~excess~~oversee ofmarket ~~changes~~conduct inand ~~the~~can ~~pipeline’s~~impose ~~operating~~significant ~~costs.~~penalties ~~Under~~for ~~FERC’s regulations~~violations, anwith ~~NGLs~~fines orpotentially ~~crude-oil~~exceeding ~~pipeline~~$1.0 ~~can~~million ~~request~~per ~~a rate increase that exceeds the rate~~ day.

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obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. A pipeline also can support a rate by showing that it has been agreed to by all shippers or by obtaining advance approval to charge market-based rates. The White Cliffs pipeline has been granted market-based rate authority by the FERC.

The Interstate Commerce Act permits interested persons to challenge proposed new rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months pending an investigation. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. The just-and-reasonable rate used to calculate refunds cannot be lower than the last tariff rate approved as just and reasonable. FERC may also investigate, upon complaint or on its own initiative, a changed rate and may order a carrier to reduce its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for charges in excess of a just-and-reasonable rate for a period of up to two years prior to the filing of a complaint. FERC’s Revised Policy on Treatment of Income Taxes (“Revised Policy Statement”), that no longer permits MLPs to recover an income tax allowance in cost-of-service rates, applies to our pipelines regulated under the Interstate Commerce Act. The Revised Policy Statement may result in an adverse impact on revenues associated with the indexed or cost-of-service rates of our FERC-regulated interstate pipelines.

As discussed above, the CFTC holds authority to monitor certain segments of the physical and futures energy commodities market. The Federal Trade Commission (the “FTC”) has authority to monitor petroleum markets to prevent market manipulation. The CFTC and FTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by the CFTC and FTC, we could be subject to substantial penalties and fines.

Natural-Gas Gathering Pipeline Regulation

Regulation of gas-gathering pipeline services may affect certain aspects of our business and the market for our products and services. Natural-gas gathering facilities are exempt from the jurisdiction of FERC. We believe that our gas-gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is not subject to FERC jurisdiction, although FERC has not made any determinations with respect to the jurisdictional status of any of our gas pipelines other than those owned by MIGC and the West Texas complex residue lines. However, the distinction between FERC-regulated gas-transmission services and federally unregulated gathering services has been the subject of substantial litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. FERC makes jurisdictional determinations on a case-by-case basis. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our natural-gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural-gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Our natural-gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural-gas gathering activities, which allows natural-gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil, and criminal remedies. To date, there has been no adverse effect on our systems resulting from these regulations.27

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~~not~~Our ~~apply~~natural-gas gathering operations are subject to ~~activities~~ratable-take ~~that~~and ~~relate~~common-purchaser ~~only~~statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to ~~intrastate~~take natural gas without undue discrimination as to source of supply or ~~other~~producer. ~~non-jurisdictional~~These ~~sales~~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, ~~but~~facilities ~~only~~to decide with whom we contract to ~~the~~gather ~~extent~~natural ~~such~~gas. ~~transactions~~The dostates ~~not~~in which we operate have adopted a ~~“nexus”~~complaint-based toregulation ~~jurisdictional~~of ~~transactions.~~natural-gas Ingathering ~~addition~~activities, ~~FERC’s~~which ~~market~~allows ~~oversight~~natural-gas producers and ~~transparency~~shippers ~~regulations~~to ~~also~~file ~~may~~complaints ~~apply~~with tostate ~~otherwise~~regulators ~~non-jurisdictional~~in ~~entities~~an effort to ~~the~~resolve ~~extent~~grievances ~~annual~~relating ~~purchases~~to gathering access and ~~sales~~rate ofdiscrimination. ~~natural~~We ~~gas~~cannot ~~reach~~predict whether such a ~~certain~~complaint ~~threshold~~will be filed against us in the future. ~~FERC’s~~Failure ~~civil~~to ~~penalty~~comply ~~authority~~with state regulations can result in the imposition of administrative, ~~described~~civil, ~~above~~and criminal remedies. To date, ~~would~~there ~~apply~~has tobeen ~~violations~~no ofadverse effect on our systems resulting from these ~~rules~~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;

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•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 ~~transporting~~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 ~~will~~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 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, which will apply to existing sources, has a longer implementation timeline, requiring each state to submit a plan to the EPA for appropriate emissions reductions within two years of the date that the rule is published, and regulated entities will be required to comply with state or federal rules within three years after the deadline for state plan submittals. Although any state-implemented rules must be at least as stringent as the federal rules, 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.

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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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~~For~~20.5% ~~example,~~reduction in ~~2024,~~combustion ~~Colorado’s~~greenhouse ~~Governor~~gas ~~Polis~~emissions ~~signed~~from ~~Senate~~the ~~Bill~~midstream ~~24-229~~sector ~~seeking~~by 2030 as compared to ~~reduce~~a ~~ozone~~2015 ~~emissions~~baseline. Such rules require, among other things, midstream operators to comply by ~~requiring~~2030 ~~the~~with ~~Colorado~~certain ~~Department~~emissions caps through various means of ~~Public~~emissions ~~Health~~reductions and/or ~~Environment~~the ~~(“CDPHE”)~~utilization toof ~~propose~~credits. ~~rules~~Further, toColorado ~~reduce~~previously adopted regulations for methane emissions from certain oil and natural-gas ~~NOx~~operations, ~~emissions~~and byimposed ~~50%~~certain byGHG ~~2030~~intensity standards, ~~relative~~which toset ~~2017~~numerical ~~levels.~~limits ~~Compliance~~of ~~with~~carbon ~~these~~dioxide ~~rules~~equivalent or(“CO2e”) ~~with~~emissions ~~any~~per ~~similar~~barrel orof ~~future~~oil ~~federal~~produced. orThe ~~state~~implementation ~~regulation~~ of ~~methane~~substantial limitations on and/or ~~other~~costs associated with GHG emissions, ~~from~~in areas where we conduct operations could, ~~among~~result ~~other~~in ~~things~~increased compliance costs, ~~require~~including ~~installation~~to ofacquire emissions allowances or comply with new ~~emission~~regulatory ~~controls~~or onreporting ~~some~~requirements, ofwhich ~~our~~developments ~~equipment~~could adversely affect demand for oil and ~~increase~~natural gas that our ~~capital~~customers ~~expenditures~~produce, ~~and~~reduce ~~operating~~demand ~~costs~~for our services, 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. Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020, which became effective in November 2016, and since this time, the United States has twice formally joined the Paris Agreement. In response to Paris Agreement commitments, the United States has established an economy-wide target of reducing its net GHG emissions by 50% - 52% below 2005 levels by 2030 and achieving net zero GHG-emissions economy-wide by no later than 2050. 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” for applicable facilities within nine segments of the oil and natural gas industry. The IRA states that it will apply to methane emissions beginning in 2024, with the first charge for 2024 emissions due in 2025 along with OOOOb/c requirements. Multiple Congressional efforts, including a direct statutory repeal and a Congressional Review Act resolution pausing implementation, have been filed in 2025 with public statements made by the Trump Administration and Congressional leaders intent on repealing it prior to any charges coming due. The Trump administration has also recently indicated its intention to withdraw from the Paris Agreement. Notwithstanding any formal withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where WES conducts operations could adversely affect demand for oil and gas.

At the state level, the Colorado Air Quality Control Commission (“AQCC”) adopted a similar rule in February 2024, imposing fees on certain operations for greenhouse gas 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 20.5% reduction in combustion greenhouse gas emissions from the midstream sector by 2030 as compared to a 2015 baseline. Pursuant to that legislation, in December 2024, the AQCC recommended the adoption of a rule that will require every existing Colorado midstream operator to comply with a 2030 emissions cap on their Colorado operations applicable to GHG emissions from fuel-burning equipment, including engines and heaters. Compliance with emissions caps may be accomplished with the utilization of credits, which may be produced by operators that emit at rates that are lower than their respective caps. Producer credits can be marketed in, or procured from, a credit market in which midstream operators and an assortment of commercial and industrial facilities may participate. Colorado previously adopted regulations for methane emissions from certain oil and natural-gas operations, and imposed certain GHG intensity standards. Generally, GHG intensity standards set numerical limits of carbon dioxide equivalent (CO2e) emissions per barrel of oil produced. Subsequently, in July 2023, the AQCC adopted a new rule, which among other things, defines how certain oil and gas facilities must calculate their greenhouse gas intensity, monitor operations to ensure compliance with intensity standards, and keep records to accurately account for emissions from their operations. 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

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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.

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TITLE TO PROPERTIES AND RIGHTS-OF-WAY

Our real property is ~~classified~~either ~~into~~owned ~~two categories: (i) parcels that we own~~ in fee title ~~and~~or ~~(ii) parcels~~held inthrough ~~which our interest derives from~~ leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. ~~Portions~~We own portions of the land onwhere ~~which~~ our plants and other major facilities are located ~~are owned by us in fee title,~~ and welease ~~believe~~the ~~that we have satisfactory title to these lands. The~~ remainder of the land onunder ~~which~~long-standing ~~our plant sites and major facilities are located is held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessor~~agreements. We ~~or our affiliates have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we~~ believe ~~that~~ we have satisfactory ~~leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee~~ title ~~of any material lease, easement, right-of-way, permit, or license held by us or~~ to ~~our title to any material lease, easement, right-of-way, permit, or lease, and we believe that we have satisfactory title to~~ all of our material leases, easements, rights-of-way, permits, and licenses.

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, ~~2024~~2025, WES employed 1,~~511~~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 ~~2024~~2025 voluntary attrition rate was ~~6.81~~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, ~~the allocation of capital~~ and ~~operational and administrative costs, and~~ our future business opportunities;

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

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

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

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

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

•cyber attacks or security breaches; and

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

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

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

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

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RISKS INHERENT IN OUR BUSINESS

We are dependent on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, ~~treat~~transport, ~~process~~recycle, ~~transport~~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, ~~treat~~transport, ~~process~~recycle, ~~transport~~treat, supply, and/or dispose. For the year ended December 31, ~~2024~~2025, and excluding the impact of equity investments, 60% of Total revenues and other, 3436% of our throughput for natural-gas assets ~~(excluding equity-investment throughput)~~, 91% of our throughput for crude-oil and NGLs assets ~~(excluding equity-investment throughput)~~, and 7861% 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 $2.71 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, ~~2024~~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 ~~recently~~increased ~~implemented~~tariffs ~~a 10% tariff~~ on most Chinese imports under its renewed Section 301 and ~~announced~~International aEmergency ~~25%~~Economic ~~tariff~~Powers onAct ~~imports~~authorities ofand has significantly increased national security-based tariffs on steel and aluminum. ~~Plans~~imports, byincluding raising the ~~Trump~~general ~~administration~~tariff torate ~~impose~~on ~~additional~~most ~~import~~steel ~~tariffs~~and onaluminum ~~Canada~~products. ~~and~~The ~~Mexico~~Trump ~~are~~administration has also ~~currently~~imposed ~~under~~and ~~consideration,~~expanded asso ~~are~~called ‘reciprocal’ tariffs on ~~all~~a ~~U.S.~~wide range of United States trading partners ~~that~~with ~~currently~~which ~~impose~~the ~~tariffs~~United States has sizable trade imbalances and has announced or threatened additional increases on ~~American~~imports ~~goods~~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 ~~2024~~2025 distribution of $0.~~87500~~91000 per unit per quarter, or $3.~~50000~~64000 per unit per year, we require per-quarter available cash of $~~341~~379.07 million, or $1,~~364~~518.08 million per year, based on the number of common units outstanding at February 32, ~~2025~~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 ~~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.~~

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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 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

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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 ~~regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which~~

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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 ~~transporting~~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 ~~geopolitical~~domestic ~~events,~~and ~~such~~international aspolitical ~~the Russian invasion of Ukraine~~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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~~numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties~~ also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects. Delays in the completion of new downstream assets, or the unavailability of existing downstream assets, due to environmental, regulatory, or political considerations, could have an adverse impact on the completion or utilization of our growth projects. In addition, construction activities could be subject to state, county, and local ordinances that restrict the time, place, or manner in which those activities may be conducted. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize.

We may fail to successfully combine our business with the assets and business of 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.

~~We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.~~43

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.

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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;

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•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 ~~380~~408,~~556~~141,~~643~~366 common units outstanding as of December 31, ~~2024.~~2025, with Occidental ~~currently~~holding ~~holds~~ 165,681,578 common units, representing 4340.56% of our outstanding common units. ~~Occidental’s shelf registration statement currently allows for the offer and sale of approximately 10.8 million common units, or 2.8% of our common units as of December 31, 2024, from time to time.~~ Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the impermissible distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

~~Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.~~45

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the ~~liability~~partnership ofagreement. ~~holders~~Neither ofliabilities ~~limited~~to ~~partner~~partners ~~interests~~on ~~for~~account ~~the obligations~~ of atheir ~~limited~~ partnership ~~have~~interest ~~not~~nor ~~been~~liabilities ~~clearly~~that ~~established~~are innon-recourse ~~some~~to of the ~~other~~partnership ~~states~~are incounted ~~which we do business. A unitholder could be liable~~ for ~~any~~purposes ~~and all~~ of ~~our~~determining ~~obligations~~whether ~~as if that unitholder were~~ a ~~general~~distribution ~~partner~~is 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 businesspermitted.

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.

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.46

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~~may~~If ~~materially~~the ~~and~~IRS ~~adversely~~were ~~impact~~to contest the ~~market~~federal ~~for~~income ~~our~~tax ~~common~~positions ~~units~~we ~~and~~take, it may impact the ~~price~~market atfor ~~which~~our ~~they~~common ~~trade.~~units ~~Moreover~~adversely, and the costs of any such contest ~~with~~would reduce the ~~IRS will result in a reduction in~~ cash available for distribution to our unitholders ~~and thus will be borne indirectly by 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 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%.

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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 (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.

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Item 1C. Cybersecurity

Our cybersecurity program is designed to promote actions that protect our computer systems and networks, delivering safe, secure, and reliable operations. Our ~~digital~~information technology group is led by aour ~~dedicated~~ Chief Information ~~Security~~ Officer (“~~CISO~~CIO”). Our ~~CISO~~CIO has 16over 20 years of information security and project management experience and has previously served as athe ~~chief~~lead information ~~security~~technology officer, ~~over~~to ~~four~~one ~~decades~~publicly oftraded ~~experience~~enterprise and the cybersecurity and infrastructure lead at a separate publicly traded enterprise, both in the energy industry,. Reporting to our CIO is a ~~degree~~Director inof ~~computer~~Cybersecurity ~~science,~~and Infrastructure (“DCI”). Our DCI has over 20 years of information technology and ~~manages~~cybersecurity experience and holds a ~~team~~Certified atInformation ~~WES~~Systems ~~that~~Security isProfessional ~~responsible~~certification ~~for~~from ~~leading~~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 ~~CISO~~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 ~~CISO~~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, inas part of our continuing commitment to cybersecurity education and preparedness, we ~~also~~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 31. 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.

WeOther 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 2113, ~~2025~~2026, there were 2694 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 914,~~500~~403,~~000~~998 units, respectively, of which ~~322~~737,~~228~~749 and 811,~~385~~655,~~682~~238 units, respectively, remained available for future issuance as of December 31, ~~2024~~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 ~~$1.25~~2025 ~~billion~~ Purchase Program during the fourth quarter of ~~2024~~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, 2024	—	$	—	—	$	627,807,310
October 1-31, 2025	—	$	—	—	$	250,000,000
November 1-30, 2024	—	—		—	627,807,310
November 1-30, 2025	—	—		—	250,000,000
December 1-31, 2024	—	—		—	627,807,310
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.

(1)In February 2022, WES announced a $1.0 billion buyback program, pursuant to which we may purchase up to $1.0 billion in aggregate value of our common units, through December 31, 2024. In November 2022, the Board authorized an increase in the program to $1.25 billion. The $1.25 billion Purchase Program expired as of December 31, 2024. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.50

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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, ~~2024~~2025, our general partner owned a 2.32% 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 ~~2022~~2023 items, and comparison of the year ended December 31, ~~2023~~2024, to the year ended December 31, ~~2022~~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, ~~2023~~2024, as filed with the SEC on February 2126, ~~2024~~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 98.01% partnership interest in WES Operating, as of December 31, ~~2024~~2025. Amounts attributable to noncontrolling interests presented in this Item 7 consist of (~~see~~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 ~~natural gas~~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, ~~2024~~2025, our assets and investments consisted of the following:

	WhollyOwned andOperated	OperatedInterests	EquityInterests
Gathering systems (1)	18	2	1
Gathering systems	13	2	1
Treating facilities	4243	3	—
Natural-gas processing plants/trains	26	3	1
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:

~~(1)Includes~~•On October 15, 2025, we closed on the ~~DBM~~acquisition ~~water~~of ~~systems~~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.

~~Significant~~•WES ~~financial~~Operating ~~and~~completed ~~operational~~the ~~events~~public ~~during~~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 ~~year~~4.650% ~~ended~~Senior ~~December 31~~Notes due 2026, ~~2024~~(ii) were used to repay amounts outstanding under its commercial paper program (including borrowings incurred to fund the cash consideration of the Aris acquisition), ~~included~~and (iii) will be used for general partnership purposes, including the ~~following:~~funding of capital expenditures. See Debt and Credit Facilities within this Item 7 for additional information.

•We closed on the sale of (i) our 33.75% interest in the Marcellus Interest systems for proceeds of $206.2 million and (ii) several equity investments to third parties for combined proceeds of $588.6 million, which included $5.9 million in pro-rata distributions through closing. See Acquisitions and Divestitures within this Item 7 for additional information.52

•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 will be used to repay a portion of certain senior notes due in 2025 and for general partnership purposes, including the funding of capital expenditures. See Liquidity and Capital Resources within this Item 2 for additional information.

•WES Operating purchased and retired $150.0 million of certain of its senior notes via open-market repurchases.

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•~~Our~~WES ~~regular~~Operating ~~fourth-quarter~~retired ~~2024~~the ~~per-unit~~total ~~distribution~~principal isamount ~~unchanged~~outstanding ~~from~~of the ~~third-~~3.100% Senior Notes due 2025 at par value during the first quarter ~~2024~~of ~~per-unit~~2025 ~~distribution~~and the 3.950% Senior Notes due 2025 at par value during the second quarter of $02025.~~875.~~

•~~Natural~~Our fourth-~~gas~~quarter ~~throughput~~2025 ~~attributable~~per-unit todistribution ~~WES~~is ~~totaled~~unchanged ~~5,052~~from ~~MMcf/d for~~ the ~~year~~third-quarter ~~ended~~2025 ~~December 31,~~per-unit ~~2024,~~distribution ~~representing~~of ~~a 14% increase compared to year ended December 31, 2023~~$0.910.

•~~Crude~~We completed the start-~~oil~~up ~~and~~of ~~NGLs~~the ~~throughput~~North ~~attributable~~Loving toplant ~~WES~~in ~~totaled~~late-February ~~530~~2025, ~~MBbls/d~~increasing ~~for~~gas ~~the~~processing ~~year~~capacity ~~ended~~at ~~December 31,~~the ~~2024,~~West ~~representing~~Texas acomplex ~~19%~~by ~~decrease~~250 ~~compared~~MMcf/d to ~~the~~a ~~year~~total ~~ended~~of ~~December 31~~2,190 ~~2023~~MMcf/d.

•Produced-water throughput attributable to WES totaled 1,124 MBbls/d for the year ended December 31, 2024, representing an 11% increase compared to the year ended December 31, 2023.

•Gross margin was $2.8 billion for the year ended December 31, 2024, representing a 19% increase compared to the year ended December 31, 2023. See Reconciliation of Non-GAAP Financial Measures within this Item 7.

•Adjusted Gross Margin for natural-gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.30 per Mcf for the year ended December 31, 2024, representing a 2% increase compared to the year ended December 31, 2023.

•Adjusted Gross Margin for crude-oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.94 per Bbl for the year ended December 31, 2024, representing a 19% increase compared to the year ended December 31, 2023.

•Adjusted Gross Margin for produced-water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.96 per Bbl for the year ended December 31, 2024, representing a 16% increase compared to the year ended December 31, 2023.

The following table provides additional information on throughput for the periods presented below:

	Year Ended December 31,
	2024	2023	Inc/(Dec)
	2025	2024	Inc/(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin	12,~~871~~042	1,~~635~~871	149	%
DJ Basin	1,~~436~~470	1,~~322~~436	92	%
Powder River Basin	~~456~~437	~~120~~456	NM(4)	%
Equity investments	~~517~~550	~~466~~517	116	%
Other	~~946~~905	~~1,050~~946	(104)	%
Total throughput for natural-gas assets	5,~~226~~404	45,~~593~~226	143	%
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin	~~243~~258	~~214~~243	146	%
DJ Basin	9297	7192	305	%
Powder River Basin	2527	525	NM8	%
Equity investments	~~144~~104	~~333~~144	(5728)	%
Other	3738	4237	~~(12)~~3	%
Total throughput for crude-oil and NGLs assets	~~541~~524	~~665~~541	(193)	%
Throughput for produced-water assets (MBbls/d)
Delaware Basin	1,~~147~~608	1,~~029~~147	1140	%
Total throughput for produced-water assets	1,~~147~~608	1,~~029~~147	1140	%

~~_________________________________________________________________________________________~~53

NM—Not meaningful

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OUR OPERATIONS

Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, ~~and~~ produced water, 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, ~~2024~~2025, and excluding the impact of equity investments, our West Texas / New Mexico and DJ Basin assets provided (i) 5358% and 3229%, respectively, of Total revenues and other, (ii) 4042% and 3130%, respectively, of our throughput for natural-gas assets ~~(excluding equity-investment throughput)~~, (iii) 61% and 23%, respectively, of our throughput for crude-oil and NGLs assets ~~(excluding equity-investment throughput)~~, and (iv) all of our throughput for produced-water assets.

For the year ended December 31, ~~2024~~2025, and excluding the impact of equity investments, 60% of Total revenues and other, 3436% of our throughput for natural-gas assets ~~(excluding equity-investment throughput)~~, 91% of our throughput for crude-oil and NGLs assets ~~(excluding equity-investment throughput)~~, and 7861% 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, ~~2024~~2025, 95and excluding the impact of equity investments, 97% of our wellhead natural-gas volume ~~(excluding equity investments)~~ and 100% of our crude-oil and produced-water throughput ~~(excluding equity investments)~~ were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) 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, or 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 ~~with~~ the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows. See Risk Factors under Part I, Item 1A of this Form 10-K.

Acquisitions and divestitures. During the ~~second~~fourth quarter of ~~2024~~2025, we closed on the ~~sale~~acquisition of ~~our~~Aris ~~33.75%~~by ~~interest~~merger in a transaction valued at $2.0 billion, including the ~~Marcellus~~cash ~~Interest~~and ~~systems~~equity ~~for~~merger ~~proceeds~~consideration, Aris’s outstanding debt of $~~206~~80.20 million, ~~resulting~~ in arevolving ~~net~~credit ~~gain~~facility onborrowings ~~sale~~that ofwere repaid at closing, and $63500.90 million ~~that~~in ~~was~~principal ~~recorded~~amount asof ~~Gain~~senior ~~(loss)~~notes. Based on ~~divestiture~~Aris ~~and~~shareholder ~~other~~consideration elections, ~~net~~we issued 26.6 million common units and paid $415.0 million in cash, funded with borrowings under the ~~consolidated~~commercial ~~statement~~paper program, in exchange for all issued and outstanding shares of ~~operations~~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.

In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF. For purposes of the discussion included in Results of Operations, the Powder River Basin complex includes our previously owned Hilight system and the assets acquired from Meritage.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments. We recognized long-lived asset and other impairments of $6.2 million and $52.9 million for the years ended December 31, 2024 and 2023, respectively. For a description of impairments recorded, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.55

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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

~~2024~~2025

~~2023~~2024

Total revenues and other (1)

3,~~605~~843,~~223~~403

3,~~106~~605,~~476~~223

Equity income, net – related parties

~~112~~85,~~385~~788

~~152~~112,~~959~~385

Total operating expenses (1)

2,~~043~~316,~~647~~676

12,~~869~~043,~~770~~647

Gain (loss) on divestiture and other, net

~~296~~(11,~~771~~113)

~~(10~~296,~~102)~~771

Operating income (loss)

1,~~970~~601,~~732~~402

1,~~379~~970,~~563~~732

Interest expense

(~~378~~390,~~513~~490)

(~~348~~378,~~228~~513)

Gain (loss) on early extinguishment of debt

~~5,403~~—

155,~~378~~403

Other income (expense), net

3116,~~741~~629

531,~~679~~741

Income (loss) before income taxes

1,~~629~~227,~~363~~541

1,~~052~~629,~~392~~363

Income tax expense (benefit)

1815,~~111~~086

418,~~385~~111

Net income (loss)

1,~~611~~212,~~252~~455

1,~~048~~611,~~007~~252

Net income (loss) attributable to noncontrolling interests

3731,~~681~~472

2537,~~791~~681

Net income (loss) attributable to Western Midstream Partners, LP (2)

1,~~573~~180,~~571~~983

1,~~022~~573,~~216~~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 ~~NGLs~~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, ~~2024~~2025” refer to the comparison of the year ended December 31, ~~2024~~2025, to the year ended December 31, ~~2023~~2024.

Discussion of ~~2022~~2023 items and comparison of the year ended December 31, ~~2023~~2024, to the year ended December 31, ~~2022~~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, ~~2023~~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,
	2024	2023	Inc/(Dec)
	2025	2024	Inc/(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation	~~453~~375	~~435~~453	4(17)	%
Processing	4,~~256~~479	34,~~692~~256	155	%
Equity investments (1)	~~517~~550	~~466~~517	116	%
Total throughput	5,~~226~~404	45,~~593~~226	143	%
Throughput attributable to noncontrolling interests (2)	174	161	8	%
Throughput attributable to noncontrolling interests	178	174	2	%
Total throughput attributable to WES for natural-gas assets	5,~~052~~226	45,~~432~~052	143	%
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation	~~397~~420	~~332~~397	206	%
Equity investments (1)	~~144~~104	~~333~~144	(5728)	%
Total throughput	~~541~~524	~~665~~541	(193)	%
Throughput attributable to noncontrolling interests (2)	11	13	(15)	%
Throughput attributable to noncontrolling interests	10	11	(9)	%
Total throughput attributable to WES for crude-oil and NGLs assets	~~530~~514	~~652~~530	(193)	%
Throughput for produced-water assets (MBbls/d)
Gathering and disposal	1,147	1,029	11	%
Gathering, disposal, and water solutions	1,608	1,147	40	%
Throughput attributable to noncontrolling interests (2)	23	20	15	%
Throughput attributable to noncontrolling interests	30	23	30	%
Total throughput attributable to WES for produced-water assets	1,124	1,009	11	%
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)~~Includes~~Water ~~(i)~~solutions ~~the~~volumes ~~2.0%~~include ~~limited~~groundwater ~~partner~~and ~~interest~~gathered inproduced ~~WES~~water ~~Operating~~that ~~owned~~is bytreated ~~an Occidental subsidiary~~ and ~~(ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests~~recycled.

Natural-gas assets

Total throughput attributable to WES for natural-gas assets increased by ~~620~~174 MMcf/d for the year ended December 31, ~~2024~~2025, primarily due to (i) higher volumes at the ~~Powder River Basin complex due to the Meritage acquisition, (ii) higher volumes at the~~ West Texas, ~~and~~ DJ Basin, and Chipeta complexes due to increased production in the areas, and (~~iii~~ii) higher volumes aton the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, ~~and~~beginning ~~(iv)~~in ~~higher~~November ~~volumes at the Springfield gas-gathering system due to new third-party production~~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, ~~and~~ (ii) lower volumes at the ~~Granger~~Springfield ~~complex~~gas-gathering system due to adecreased ~~contract~~production ~~expiration~~ in the ~~fourth~~area, ~~quarter~~and of(iii) ~~2023~~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 ~~122~~16 MBbls/d for the year ended December 31, ~~2024~~2025, primarily due to (i) the divestiture of Whitethorn LLC, ~~Mont~~and ~~Belvieu JV,~~ Saddlehorn, ~~and Panola~~ in the first quarter of 2024 and (ii) lower volumes on the TEP pipeline. These decreases were offset partially by ~~(i)~~ higher volumes at the DBM ~~and DJ Basin~~ oil ~~systems~~system due to increased production in the ~~areas and (ii) higher volumes at the Thunder Creek NGL pipeline, which was acquired as part of the Meritage acquisition~~area.

Produced-water assets

Total throughput attributable to WES for produced-water assets increased by ~~115~~454 MBbls/d for the year ended December 31, ~~2024~~2025, due to ~~higher~~(i) ~~production,~~the ~~partially~~acquisition ~~offset~~of byAris ~~increased~~and ~~recycling~~(ii) ~~activities~~higher ~~in the upstream operations of our producers~~production.

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~~Service~~ Revenues

	Year Ended December 31,
thousands except percentages	2024		2023		Inc/(Dec)
thousands except percentages and per-unit amounts	2025		2024		Inc/(Dec)
Service revenues – fee based	$	3,~~248~~453,~~262~~052	$	23,~~768~~248,~~757~~262	176	%
Service revenues – product based	215,776		191,727		13	%
Other revenues from customers
Total service revenues	$	3,464,038	$	2,960,484	17	%
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 $~~479~~204.58 million for the year ended December 31, ~~2024~~2025, primarily due to increases of (i) $~~184~~105.06 million at the ~~West~~DBM ~~Texas~~water ~~complex~~systems due to ~~increased~~the ~~throughput,~~acquisition ~~a higher average fee resulting from a cost-~~of~~-service~~ ~~rate~~Aris ~~redetermination effective January 1, 2024,~~ and increased ~~deficiency fees on certain contracts with increasing~~ throughput ~~minimums~~, ~~(ii)~~partially ~~$140.2~~offset ~~million~~by ata ~~the~~change ~~Powder~~in ~~River~~contract ~~Basin~~terms ~~complex~~effective ~~attributable~~January to1, ~~the acquisition of Meritage~~2025, (~~iii~~ii) $8998.85 million at the DJWest ~~Basin~~Texas complex primarily due to increased throughput ~~and increased electricity-related rates billed to customers~~, partially offset by adecreased ~~decrease in~~ deficiency fees on certain contracts with throughput minimums, (iviii) $8732.56 million ~~and $36.7 million~~ at the DBM ~~water and DBM~~ oil ~~systems,~~system ~~respectively,~~due asto ~~a result of~~ increased throughput, ~~and~~ higher average fees resulting from cost-of-service rate redeterminations effective January 1, ~~2024~~2025, and deficiency fees on certain contracts with increasing throughput minimums, and (viv) $610.71 million at the ~~Chipeta~~DJ Basin complex primarily due to ~~new~~increased ~~and amended contracts effective July 2024~~throughput. These increases were offset partially by decreases of (i) $2332.74 million at the ~~Marcellus~~Springfield ~~Interest~~ systems due to ~~the~~decreased ~~sale~~throughput ofand ~~the~~lower ~~asset~~annual ~~during~~cumulative ~~the~~catch-up ~~second~~adjustments ~~quarter~~for cost-of-service changes in estimated consideration in 2025 compared to 2024, (ii) $1618.87 million ~~and $4.3 million~~ at the ~~Springfield and~~ DJ Basin oil ~~systems,~~system ~~respectively, primarily~~ due to ~~decreased revenues associated with demand volumes and~~ lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in ~~2024~~2025 compared to ~~2023~~2024, partially offset by increased throughput, and ~~higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024,~~ (iii) $11.80 million at the ~~Granger~~Marcellus ~~complex~~Interest systems due to ~~a contract expiration in~~ the ~~fourth~~sale ~~quarter~~ of ~~2023,~~the ~~and~~asset ~~(iv)~~during ~~$10.5 million at~~ the ~~Brasada~~second ~~complex~~quarter ~~due~~of ~~to a change in contract terms effective July 1, 2023, partially offset by increased throughput~~2024.

~~Service~~Other revenues –from ~~product based~~customers

~~Service~~Other revenues –from ~~product~~customers ~~based~~ increased by $2432.07 million for the year ended December 31, ~~2024~~2025, primarily due to ~~increases of~~ (i) $1552.48 million at the West Texas complex due to increased volumes sold, ~~(ii)~~and ~~$5.3~~net ~~million at the DJ Basin complex due to a contract change effective during the second quarter of 2024, partially offset by decreased~~ average prices, and (~~iii~~ii) $429.71 million at the ~~Powder~~DBM ~~River~~water ~~Basin~~systems ~~complex~~due ~~attributable~~ to the acquisition of ~~Meritage,~~Aris and ~~(iv) $2.3 million at the DBM water systems due to~~ increased ~~skim-oil~~ volumes sold. These increases were offset partially by a decrease of $335.45 million at the ~~Chipeta~~DJ Basin complex primarily due to ~~decreased~~lower volumes sold and average prices.

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Product Sales

	Year Ended December 31,
thousands except percentages and per-unit amounts	2024		2023		Inc/(Dec)
Natural-gas sales	$	13,469	$	40,679	(67)	%
NGLs sales	126,631		104,345		21	%
Total Product sales	$	140,100	$	145,024	(3)	%
Per-unit gross average sales price:
Natural gas (per Mcf)	$	0.29	$	1.66	(83)	%
NGLs (per Bbl)	28.62		27.89		3	%

Natural-gas sales

Natural-gas sales decreased by $27.2 million for the year ended December 31, 2024, primarily due to a decrease of $33.6 million at the West Texas complex due to decreased average prices. This decrease was offset partially by increases of (i) $8.9 million at the Powder River Basin complex attributable to the acquisition of Meritage and (ii) $3.1 million at the DJ Basin complex as a result of changes in contract mix during the second quarter of 2023.

NGLs sales

NGLs sales increased by $22.3 million for the year ended December 31, 2024, primarily due to increases of (i) $21.3 million at the Powder River Basin complex attributable to the acquisition of Meritage and (ii) $14.8 million at the DJ Basin complex due to increased volumes sold, partially offset by decreased average prices and the impact of a contract change effective during the second quarter of 2024. These increases were offset partially by decreases of (i) $7.8 million at the West Texas complex due to changes in contract mix and decreased average prices, partially offset by increased volumes sold and (ii) $4.7 million at the Chipeta complex due to a contract change effective during the third quarter of 2024.

Equity Income, Net – Related Parties

Year Ended December 31,

thousands except percentages

~~2024~~2025

~~2023~~2024

Inc/(Dec)

Equity income, net – related parties

~~112~~85,~~385~~788

~~152~~112,~~959~~385

(2724)

Equity income, net – related parties decreased by $4026.6 million for the year ended December 31, ~~2024~~2025, primarily due to decreases of ~~(i)~~ $377.6 million ~~resulting from the sale of several equity investments to third parties in the first quarter of 2024~~ and ~~(ii)~~ $87.0 million at TEP. ~~These decreases were offset partially by an increase of $4.6 million at Red Bluff. See Note 3—Acquisitions~~ and ~~Divestitures~~Mi ~~in the Notes to Consolidated Financial Statements under Part II~~Vida, ~~Item 8 of this Form 10-K~~respectively.

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Cost of Product and Operation and Maintenance Expenses

Year Ended December 31,

thousands except percentages

~~2024~~2025

~~2023~~2024

Inc/(Dec)

Natural-gas purchases

1033,~~586~~941

3210,~~515~~586

~~(67)~~NM

NGLs purchases

~~252~~240,~~591~~109

~~211~~252,~~468~~591

19(5)

Other

(9067,~~926~~072)

(7990,~~385~~926)

~~(15)~~26

Cost of product

~~172~~206,~~251~~978

~~164~~172,~~598~~251

520

Operation and maintenance

~~880~~915,~~568~~896

~~762~~880,~~530~~568

154

Total Cost of product and Operation and maintenance expenses

1,~~052~~122,~~819~~874

~~927~~1,~~128~~052,819

147

Natural-gas purchases

Natural-gas purchases ~~decreased~~increased by $2123.94 million for the year ended December 31, ~~2024~~2025, primarily due to ~~decreases of~~ (i) ~~$15.3~~higher ~~million~~average prices at the West Texas complex ~~due to lower average prices~~ and (ii) ~~$6.2~~increased ~~million~~purchases at the ~~Granger~~Chipeta complex ~~attributable to a contract change effective during 2023 and decreased volumes purchased~~.

NGLs purchases

NGLs purchases ~~increased~~decreased by $4112.15 million for the year ended December 31, ~~2024~~2025, primarily due to ~~increases~~a decrease of ~~(i)~~ $3917.46 million at the ~~West~~DJ ~~Texas~~Basin complex ~~primarily~~due ~~attributable~~ to ~~increased~~lower ~~volumes~~ purchased volumes and average prices, ~~and~~partially ~~(ii) $4.2 million at the DJ Basin complex due to a contract change effective during the second quarter of 2024. These increases were~~ offset ~~partially~~ by aan ~~decrease~~increase of $511.61 million ~~at the Chipeta complex~~ due to ~~a contract change effective during~~ the ~~third~~acquisition ~~quarter~~ of ~~2024~~Aris.

Other items

Other items ~~decreased~~increased by $1123.59 million for the year ended December 31, ~~2024~~2025, primarily due to ~~decreases~~changes ofin ~~$32.5~~imbalance ~~million~~positions ~~and $2.3 million~~ at the West Texas and ~~Chipeta complexes, respectively, due to changes in imbalance positions. These decreases were offset partially by increases of (i) $14.9 million at the~~ Powder River Basin ~~complex primarily attributable to the acquisition of Meritage and (ii) $13~~complexes.~~6 million at the DJ Basin complex primarily attributable to changes in imbalance positions.~~

Operation and maintenance expense

~~Including~~Operation ~~the impact of operating the assets acquired with Meritage, operation~~ and maintenance expense increased by $~~118~~35.03 million for the year ended December 31, ~~2024~~2025, primarily due to increases of (i) $3848.53 million inrelated ~~salaries~~to ~~and~~the ~~wages~~acquisition ~~costs~~of Aris, (ii) $2512.14 million in ~~equipment,~~utility ~~materials~~expense, ~~maintenance,~~ and ~~repair costs,~~ (iii) $166.72 million in ~~chemical~~land-related ~~and~~costs. ~~treating~~These ~~services,~~amounts were offset partially by decreases of (ivi) $107.27 million in ~~land-related~~chemicals ~~costs~~and treating services, (vii) $97.06 million in ~~equipment~~contract ~~rental~~labor and consulting costs, (viiii) $76.12 million in ~~water~~mechanical-~~disposal~~integrity costs, and (~~vii~~iv) $56.41 million in ~~utility~~regulatory and environmental expense.

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Other Operating Expenses

Year Ended December 31,

thousands except percentages

~~2024~~2025

~~2023~~2024

Inc/(Dec)

General and administrative

~~271~~398,~~526~~922

~~232~~271,~~632~~526

1747

Property and other taxes

6269,~~668~~342

5662,~~458~~668

Depreciation and amortization

~~650~~710,~~428~~778

~~600~~650,~~668~~428

Long-lived asset and other impairments

614,~~206~~760

526,~~884~~206

~~(88)~~138

Total other operating expenses

~~990~~1,~~828~~193,802

~~942~~990,~~642~~828

520

General and administrative expenses

General and administrative expenses increased by $38127.94 million for the year ended December 31, ~~2024~~2025, primarily due to ~~increases of (i)~~ $27120.5 million in ~~personnel~~acquisition-related ~~costs~~expenses associated with the Aris transaction, ~~(ii)~~including $10104.56 million in ~~information~~severance ~~technology~~payments ~~costs,~~ and ~~(iii)~~ $715.09 million in ~~other~~professional ~~corporate-related~~services ~~expenses.~~for ~~These~~financial ~~increases~~advisory, ~~were~~legal, ~~offset~~and ~~partially~~other byprofessional ~~a decrease of $6~~fees.~~1 million in contract labor and consulting costs.~~

Property and other taxes

Property and other taxes increased by $6.2 million for the year ended December 31, 2024, primarily due to increases of (i) $2.4 million at the DJ Basin complex primarily due to a lower ad valorem property tax accrual recorded during 2023 related to the finalization of 2022 assessments, (ii) $2.3 million at the Powder River Basin complex due to the acquisition of Meritage, and (iii) $2.0 million due to higher property tax values from expansion in West Texas.

Depreciation and amortization expense

Depreciation and amortization expense increased by $4960.84 million for the year ended December 31, ~~2024~~2025, primarily due to ~~increases of~~ (i) $4431.~~7 million at the Powder River Basin complex primarily attributable to the acquisition of Meritage and (ii) $22.5 million and $7.~~2 million atin ~~the West Texas complex and DBM water systems, respectively, primarily related to~~ capital projects being placed into service. ~~These increases were offset partially by decreases of (i) $13.3 million~~ at the DJWest ~~Basin~~Texas complex ~~primarily due to acceleration of depreciation expense during 2023~~ and ~~updated salvage values,~~ (ii) $621.45 million ~~due~~related to the ~~sale~~acquisition of ~~the Marcellus Interest systems in the second quarter of 2024, and (iii) $4~~Aris.~~3 million at the Brasada complex due to an update in the expected useful life.~~

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, ~~2024~~2025, ~~was~~ primarily due to a $410.2 8 million impairment ofat ~~certain~~the ~~corporate~~Granger ~~office leases that are no longer being utilized~~complex.

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

For further information on Long-lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Interest Expense

Year Ended December 31,

thousands except percentages

~~2024~~2025

~~2023~~2024

Inc/(Dec)

Long-term and short-term debt

(~~377~~387,~~850~~493)

(~~348~~377,~~393~~850)

Finance lease liabilities

(2,~~573~~182)

(12,~~083~~573)

~~138~~(15)

Commitment fees and amortization of debt-related costs

(1311,~~305~~001)

(1213,~~395~~305)

7(17)

Capitalized interest

1510,~~215~~186

1315,~~643~~215

12(33)

Interest expense

(~~378~~390,~~513~~490)

(~~348~~378,~~228~~513)

Interest expense increased by $3012.30 million for the year ended December 31, ~~2024~~2025, primarily due to increases of (i) $2928.32 million of interest incurred on the 65.~~350~~450% Senior Notes due ~~2029~~2034 that were issued during the third quarter of ~~2023~~2024, (ii) $166.14 million of interest incurred on the 57.~~450~~250% Senior Notes due ~~2034~~2030 that were ~~issued~~assumed ~~during~~as ~~the~~part ~~third quarter~~ of ~~2024,~~the ~~(iii)~~acquisition ~~$12.1 million~~ of ~~interest~~Aris ~~incurred on the 6.150% Senior Notes due 2033 that were issued~~ during the ~~second~~fourth quarter of ~~2023~~2025, and (iviii) $25.70 million due to ~~borrowings~~lower incapitalized ~~2024 on the commercial paper program that was established during the fourth quarter of 2023~~interest. These increases were offset partially by ~~decreases~~a decrease of ~~(i)~~ $1430.80 million ~~primarily~~ due to nosenior ~~outstanding~~note ~~borrowings~~repayments ~~under the RCF~~ during ~~2024 and (ii) $14~~2025.6 ~~million due to credit-rating related interest-rate changes and lower outstanding balances on certain senior notes due to debt repurchases.~~ 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

~~2024~~2025

~~2023~~2024

Inc/(Dec)

Other income (expense), net

3116,~~741~~629

531,~~679~~741

NM(48)

Other income (expense), net ~~increased~~decreased by $2615.1 million for the year ended December 31, ~~2024~~2025, primarily due to lower interest income earned ~~resulting~~on ~~from higher~~ cash ~~and~~investments ~~cash equivalent balances~~ throughout ~~2024~~2025.

Income Tax Expense (Benefit)

	Year Ended December 31,
thousands except percentages	~~2024~~2025			~~2023~~2024			Inc/(Dec)
Income (loss) before income taxes	$	1,~~629~~227,~~363~~541		$	1,~~052~~629,~~392~~363		55(25)	%
Income tax expense (benefit)	1815,~~111~~086			418,~~385~~111			NM(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. ~~For~~Income ~~the~~tax ~~year~~expense ~~ended~~decreased ~~December~~by ~~31,~~$3.0 ~~2024,~~million ~~the~~for ~~variance from~~ the ~~federal~~year ~~statutory~~ended ~~rate~~December 31, ~~was~~2025, primarily ~~impacted~~due byto aTexas ~~state~~ margin tax ~~rate~~liability ~~increase~~and ~~associated~~federal ~~with~~income notax ~~longer~~on ~~being~~activities ~~included~~operated inthrough ~~Occidental’s~~corporate ~~affiliated~~entities. ~~group~~See ~~tax~~Note 1—Summary ~~return~~of ~~beginning~~Significant inAccounting ~~September~~Policies ~~2024~~and ~~due~~Basis ~~to Occidental’s sale~~ of ~~19.5~~Presentation ~~million~~and ~~WES~~Note 8—Income ~~common~~Taxes ~~units~~ in ~~August~~the ~~2024~~Notes ~~and~~to ~~the~~Consolidated ~~resulting~~Financial ~~decrease~~Statements inunder ~~WES ownership~~Part II, ~~inclusive~~Item 8 of ~~its~~this ~~ownership~~Form ~~in WES Operating~~10-K.

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RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

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

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

65Adjusted 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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~~Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow are not defined in GAAP.~~ The ~~GAAP~~following ~~measure~~tables ~~that~~present isreconciliations ~~most~~of ~~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~~our ~~Cash Flow is net cash provided by operating activities. Our~~ non-GAAP ~~financial~~ measures of Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.:

Management compensates for the limitations of Adjusted Gross Margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results.





	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

The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non-GAAP financial measure of Adjusted Gross Margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Free Cash Flow:

	Year Ended December 31,
thousands	2024		2023
Reconciliation of Gross margin to Adjusted Gross Margin
Total revenues and other	$	3,605,223	$	3,106,476
Less:
Cost of product	172,251		164,598
Depreciation and amortization	650,428		600,668
Gross margin	2,782,544		2,341,210
Add:
Distributions from equity investments	142,236		194,273
Depreciation and amortization	650,428		600,668
Less:
Reimbursed electricity-related charges recorded as revenues	117,906		102,109
Adjusted Gross Margin attributable to noncontrolling interests (1)	80,509		70,195
Adjusted Gross Margin	$	3,376,793	$	2,963,847

_________________________________________________________________________________________

(1)Includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests.

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To facilitate investor and industry analysis, we also disclose per-Mcf Adjusted Gross Margin for natural-gas assets, per-Bbl Adjusted Gross Margin for crude-oil and NGLs assets, and per-Bbl Adjusted Gross Margin for produced-water assets.

Year Ended December 31,

thousands except per-unit amounts

~~2024~~2025

~~2023~~2024

Gross margin

Gross margin for natural-gas assets (1)

2,~~073~~113,~~533~~810

12,~~738~~073,~~125~~533

Gross margin for crude-oil and NGLs assets (1)

~~395~~407,~~886~~211

~~368~~395,~~444~~886

Gross margin for produced-water assets (1)

~~341~~435,~~784~~501

~~259~~341,~~541~~784

Per-Mcf Gross margin for natural-gas assets (2)

1.0807

1.0408

Per-Bbl Gross margin for crude-oil and NGLs assets (2)

2.0013

12.5200

Per-Bbl Gross margin for produced-water assets (2)

0.8174

0.6981

Adjusted Gross Margin

Adjusted Gross Margin for natural-gas assets

2,~~411~~471,~~438~~011

2,~~067~~411,~~528~~438

Adjusted Gross Margin for crude-oil and NGLs assets

~~570~~564,~~476~~461

~~589~~570,~~091~~476

Adjusted Gross Margin for produced-water assets

~~394~~514,~~879~~085

~~307~~394,~~228~~879

Per-Mcf Adjusted Gross Margin for natural-gas assets (3)

1.30

1.2830

Per-Bbl Adjusted Gross Margin for crude-oil and NGLs assets (3)

23.9401

2.4894

Per-Bbl Adjusted Gross Margin for produced-water assets (3)

0.9689

0.8396

_________________________________________________________________________________________

(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	~~2024~~2025		~~2023~~2024
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)	$	1,~~611~~212,~~252~~455	$	1,~~048~~611,~~007~~252
Add:
Distributions from equity investments	~~142~~122,~~236~~364		~~194~~142,~~273~~236
Non-cash equity-based compensation expense	37,994		32,005
Non-cash equity-based compensation expense (1)	50,803		37,994
Interest expense	~~378~~390,~~513~~490		~~348~~378,~~228~~513
Income tax expense	1815,~~111~~086		418,~~385~~111
Depreciation and amortization	~~650~~710,~~428~~778		~~600~~650,~~668~~428
Impairments	6,206		52,884
Long-lived asset and other impairments	14,760		6,206
Other expense	~~248~~303		~~1,739~~248
Less:
Gain (loss) on divestiture and other, net	~~296~~(11,~~771~~113)		~~(10~~296,~~102)~~771
Gain (loss) on early extinguishment of debt	~~5,403~~—		155,~~378~~403
Equity income, net – related parties	~~112~~85,~~385~~788		~~152~~112,~~959~~385
Other income	3116,~~741~~629		631,~~976~~741
Adjusted EBITDA attributable to noncontrolling interests (1)	54,650		48,345
Items impacting comparability
Adjusted EBITDA	$	2,344,038	$	2,068,633
Acquisition-related expenses (1)	(113,188)		—
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Adjusted EBITDA attributable to noncontrolling interests	58,141		54,650
Net cash provided by operating activities	$	2,136,860	$	1,661,334
Adjusted EBITDA (2)	$	2,480,782	$	2,344,038
Interest (income) expense, net	378,513		348,228
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Accretion and amortization of long-term obligations, net	(9,238)		(8,151)
Net cash provided by operating activities	$	2,222,625	$	2,136,860
Current income tax expense (benefit)	3,900		3,341
Interest (income) expense, net	390,490		378,513
Other (income) expense, net	(31,741)		(5,679)
Accretion and amortization of long-term obligations, net	(6,945)		(9,238)
Distributions from equity investments in excess of cumulative earnings – related parties	30,850		39,104
Current income tax expense (benefit)	11,142		3,900
Changes in assets and liabilities:
Other (income) expense, net	(16,629)		(31,741)
Accounts receivable, net	42,798		78,346
Distributions from equity investments in excess of cumulative earnings – related parties	31,391		30,850
Accounts and imbalance payables and accrued liabilities, net	21,935		68,019
Changes in assets and liabilities:
Other items, net	(175,189)		(67,564)
Accounts receivable, net	(36,018)		42,798
Adjusted EBITDA attributable to noncontrolling interests (1)	(54,650)		(48,345)
Accounts and imbalance payables and accrued liabilities, net	3,969		21,935
Adjusted EBITDA	$	2,344,038	$	2,068,633
Other items, net	(174,290)		(175,189)
Cash flow information
Acquisition-related expenses (1)	113,188		—
Net cash provided by operating activities	$	2,136,860	$	1,661,334
Adjusted EBITDA attributable to noncontrolling interests	(58,141)		(54,650)
Net cash provided by (used in) investing activities	(39,168)		(1,607,291)
Adjusted EBITDA (2)	$	2,480,782	$	2,344,038
Net cash provided by (used in) financing activities	(1,280,015)		(67,912)
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)~~Includes~~Acquisition-related expenses include (i) ~~the~~$97.3 ~~25%~~million ~~third-party~~of ~~interest~~severance incosts ~~Chipeta~~ and (ii) ~~the 2~~$15.0%9 ~~limited~~million ~~partner~~of ~~interest~~third-party inconsulting ~~WES~~and ~~Operating~~legal ~~owned~~fees. byNon-cash anequity-based ~~Occidental~~compensation ~~subsidiary~~expense for the year ended December 31, ~~which~~2025, ~~collectively~~includes ~~represent~~$7.3 million ~~WES’s~~in ~~noncontrolling~~acquisition-related ~~interests~~severance costs.

68(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	~~2024~~2025		~~2023~~2024
Reconciliation of Net cash provided by operating activities to Free Cash Flow
Net cash provided by operating activities	$	2,~~136~~222,~~860~~625	$	12,~~661~~136,~~334~~860
Less:
Capital expenditures	~~833~~727,~~856~~991		~~735~~833,~~080~~856
Contributions to equity investments – related parties	9,690		1,153
Contributions to equity investments (including capitalized interest)	—		9,690
Add:
Distributions from equity investments in excess of cumulative earnings – related parties	30,850		39,104
Distributions from equity investments in excess of cumulative earnings — related parties	31,391		30,850
Free Cash Flow	$	1,~~324~~526,~~164~~025	$	~~964~~1,~~205~~324,164
Cash flow information
Net cash provided by operating activities	$	2,~~136~~222,~~860~~625	$	12,~~661~~136,~~334~~860
Net cash provided by (used in) investing activities	(39,168)		(1,607,291)
Net cash used in investing activities	(1,085,206)		(39,168)
Net cash provided by (used in) financing activities	(1,280,015)		(67,912)
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 ~~Service~~ Revenues, ~~Product Sales,~~ Cost of Product (Natural-gas purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).

Gross margin increased by $~~441~~143.31 million for the year ended December 31, ~~2024~~2025, primarily due to a $~~498~~238.72 million increase in total revenues and other., ~~This~~partially ~~increase was~~ offset ~~partially~~ by ~~(i)~~ a $4960.84 million increase in depreciation and amortization ~~and (ii) a $7~~.~~7 million increase in cost of product.~~

Net income (loss). Refer to Operating Results within this Item 7 for a discussion of the primary components of Net income (loss) as compared to the prior periods.

Net income (loss) ~~increased~~decreased by $~~563~~398.28 million for the year ended December 31, ~~2024~~2025, primarily due to (i) a $~~498~~307.~~7 million increase in total revenues and other and (ii) a $306.~~9 million ~~increase~~decrease in gain (loss) on divestiture and other, net. ~~These~~and ~~amounts were offset partially by~~ (iii) a $~~173~~273.90 million increase in total operating expenses~~, (ii) a $40~~.6 ~~million~~These ~~decrease~~amounts inwere ~~equity~~offset ~~income,~~partially ~~net~~by ~~– related parties, and (iii)~~ a $30238.3 2 million increase in ~~interest~~total ~~expense~~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.

6965

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KEY PERFORMANCE METRICS

	Year Ended December 31,
thousands except percentages and per-unit amounts	~~2024~~2025		~~2023~~2024		Inc/(Dec)
Adjusted Gross Margin	$	3,~~376~~549,~~793~~557	$	23,~~963~~376,~~847~~793	145	%
Per-Mcf Adjusted Gross Margin for natural-gas assets (1)	1.30		1.2830		2—	%
Per-Bbl Adjusted Gross Margin for crude-oil and NGLs assets (1)	23.9401		2.4894		192	%
Per-Bbl Adjusted Gross Margin for produced-water assets (1)	0.9689		0.8396		16(7)	%
Adjusted EBITDA	2,~~344~~480,~~038~~782		2,~~068~~344,~~633~~038		136	%
Free cash flow	1,324,164		964,205		37	%
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 $~~412~~172.98 million for the year ended December 31, ~~2024~~2025, primarily due to (i) ~~increased~~the ~~throughput~~acquisition ~~and~~of aAris ~~higher~~and ~~average~~increased ~~fee~~throughput ~~resulting~~at ~~from~~the ~~cost-of-service~~DBM ~~rate~~water ~~redeterminations~~systems ~~effective~~and ~~January~~(ii) 1,increased ~~2024,~~throughput at the West Texas complex, ~~DBM water systems,~~ and DBM oil system,. ~~(ii)~~These ~~increased~~increases ~~throughput~~were atoffset ~~the~~partially ~~Powder~~by ~~River~~(i) ~~Basin~~lower ~~complex~~annual ~~attributable~~cumulative tocatch-up ~~the~~adjustments ~~acquisition~~for cost-of-service ~~Meritage,~~changes ~~and~~in ~~(iii)~~estimated ~~increased~~consideration ~~throughput~~in at2025 ~~the~~compared DJto ~~Basin~~2024 ~~complex.~~and ~~These~~decreased ~~increases~~throughput ~~were~~at ~~offset~~the ~~partially~~Springfield bygas-gathering system, (iii) the sale of our interests in the Marcellus Interest systems, Saddlehorn, and Mont Belvieu JV, ~~and Saddlehorn~~ during 2024, (~~ii) decreased distributions from TEP, (~~iii) ~~decreased revenues associated with demand volumes and a~~ lower annual cumulative catch-up ~~adjustment~~adjustments for cost-of-service changes in estimated consideration in ~~2024~~2025 compared to ~~2023 at the Springfield system~~2024, partially offset by increased throughput ~~and~~at ~~higher~~the ~~average~~DJ ~~fees~~Basin ~~resulting~~oil ~~from cost-of-service rate redeterminations effective January 1~~system, ~~2024,~~ and (iv) decreased ~~processing~~throughput ~~fees~~ at the ~~Brasada~~Granger complex ~~resulting from a change in contract terms effective July 1, 2023, partially offset by increased throughput~~.

Per-Mcf Adjusted ~~Gross~~gross ~~Margin~~margin for natural-gas assets ~~increased~~was byunchanged ~~$0.02~~ for the year ended December 31, ~~2024~~2025, primarily due to ~~(i)~~ increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, inoffset ~~addition~~by tolower ~~a higher~~ average ~~fee~~prices ~~resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums, and (ii) increased throughput~~ at the DJ Basin complex~~, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets~~.

Per-Bbl Adjusted ~~Gross~~gross ~~Margin~~margin for crude-oil and NGLs assets increased by $0.4607 for the year ended December 31, ~~2024~~2025, primarily due to (i) ~~the~~increased ~~sale~~throughput ofat ~~our interests in Whitethorn LLC, Mont Belvieu JV, and Saddlehorn in~~ the ~~first~~DBM ~~quarter~~oil ~~of 2024~~system, ~~all of~~ which ~~had~~has ~~lower~~a higher-than-average per-Bbl ~~margins~~margin as compared to our other crude-oil and NGLs assets, ~~and~~ (ii) ~~increased~~lower throughput at ~~the~~TEP ~~DBM~~and ~~oil system~~FRP, which ~~has~~have ~~a higher~~lower-than-average per-~~Mcf~~Bbl ~~margin~~margins as compared to our other crude-oil and NGLs assets, inand ~~addition~~(iii) tothe asale ~~higher~~of ~~average~~our ~~fee~~interest ~~resulting~~in ~~from~~Whitethorn LLC which had a ~~cost~~lower-ofthan-~~service~~average ~~rate~~per-Bbl ~~redetermination~~margin ~~effective~~as ~~January~~compared 1,to ~~2024~~our other crude-oil and NGLs assets. These increases were offset partially by ~~(i)~~ decreased revenues associated with ~~demand volumes and~~ lower annual cumulative catch-up adjustments for cost-of-service changes ~~in estimated consideration in 2024 compared to 2023~~ at the DJ Basin oil and Springfield oil-gathering systems, ~~partially~~that ~~offset~~increased byrevenues ~~higher~~in ~~average~~the ~~fees~~fourth ~~resulting~~quarter ~~from cost-~~of~~-service~~ ~~rate~~2024 ~~redeterminations~~and ~~effective~~decreased ~~January~~revenues 1,in ~~2024,~~the ~~and~~fourth ~~(ii)~~quarter ~~decreased~~of ~~distributions at TEP~~2025.

Per-Bbl Adjusted Gross Margin for produced-water assets ~~increased~~decreased by $0.1307 for the year ended December 31, ~~2024~~2025, primarily due to ~~higher~~the ~~throughput~~acquisition ~~and a higher average fee resulting from a cost-~~of~~-service~~ ~~rate redetermination effective January 1, 2024~~Aris.

Adjusted EBITDA. Adjusted EBITDA increased by $~~275~~136.47 million for the year ended December 31, ~~2024~~2025, primarily due to a $~~498~~238.72 million increase in total revenues and other. This amount was offset partially by (i) a $~~118~~35.03 million increase in operation and maintenance expenses, (ii) a $5234.07 million ~~decrease~~increase in ~~distributions~~cost ~~from~~of ~~equity~~product ~~investments,~~ (~~iii)~~net aof ~~$32.9~~lower ~~million~~of ~~increase~~cost inor ~~general~~market ~~and~~inventory ~~administrative expenses excluding non-cash equity-based compensation expense~~adjustments), (iviii) a $719.89 million ~~increase~~decrease in ~~cost~~distributions offrom ~~product~~equity ~~(net of lower of cost or market inventory adjustments)~~investments, and (viv) a $6.27 million increase in property ~~and other~~ taxes.

70Free 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.

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Free Cash Flow. Free Cash Flow increased by $360.0 million for the year ended December 31, 2024, primarily due to a $475.5 million increase in net cash provided by operating activities, partially offset by (i) a $98.8 million increase in capital expenditures, (ii) an $8.5 million increase in contributions to equity investments, and (iii) an $8.3 million decrease in distributions from equity investments in excess of cumulative earnings.

See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

GENERAL TRENDS AND OUTLOOK

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

Impact of producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude-oil, natural-gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. The New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude-oil daily settlement prices during 2023 ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023, and prices during the year ended December 31, 2024, ranged from a low of $65.75 per barrel in September 2024 to a high of $86.91 per barrel in April 2024. The Waha Hub natural-gas price during 2023 ranged from a low of ($3.8400) per MMBtu in January 2023 to a high of $3.2750 per MMBtu in January 2023, and prices during the year ended December 31, 2024, ranged from a low of ($6.2250) per MMBtu in August 2024 to a high of $8.2650 per MMBtu in January 2024. The extent and duration of commodity-price volatility, and the associated direct and indirect impact on our business, cannot be predicted. To address the risks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, oil and gas takeaway constraints, produced water recycling and disposal limitations, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can have a significant impact on the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise.

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

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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.

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. ~~Although~~and ~~somewhat~~tariffs. ~~abated~~High ~~during~~inflation ~~2024,~~in the U.S. ~~economy~~ has ~~recently experienced significant inflation relative to historical precedent. Inflation has~~ raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, ~~which~~raising ~~has increased our~~ operating costs and capital expenditures. Additionally, the Trump administration has ~~recently~~imposed ~~implemented~~significant aimport ~~10%~~tariffs, ~~tariff~~including on ~~Chinese~~ imports ~~and announced a 25% tariff on imports~~ of steel and aluminum., ~~Plans~~and bymay ~~the Trump administration to~~ impose ~~additional~~further ~~import~~ tariffs on ~~Canada~~other ~~and Mexico are also currently under consideration, as are reciprocal tariffs on all~~ U.S. trading partners ~~that currently impose tariffs on American goods~~. These ~~and other import~~ tariffs could substantially increase our operating and capital costs. ~~Although~~While ~~we cannot predict any~~ future inflation ~~trends~~and ortariff ~~the~~impacts ~~impact~~are ~~of current or future import tariffs~~uncertain, higher operating and capital costs could materially and negatively ~~impact~~affect ~~our~~ financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Short- and long-term interest rates can be volatile, resulting in immediate changes to interest expense on RCF borrowings and commercial paper borrowings. Any future increases in interest rates likely will result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our peers face similar interest-rate dynamics.67

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

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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, ~~2024~~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. ~~Under~~We ~~our partnership agreement, we~~ distribute all of our available cash, ~~(beyond proper reserves~~ as defined in our partnership agreement), within 55 days following each quarter’s end. Our cash flow and resulting ability to make cash distributions are dependent on our ability to generate cash flow from operations. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves, and cash on hand resulting from working capital borrowings made after the end of the quarter. The general partner establishes cash reserves to provide for the proper conduct of our business, including (i) to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. The Board declared a cash distribution to unitholders for the fourth quarter of ~~2024~~2025 of $0.~~875~~910 per unit, or $~~341~~379.07 million in the aggregate. The cash distribution was paid on February 1413, ~~2025~~2026, to our unitholders of record at the close of business on February 32, ~~2025~~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 ~~particular amount of~~ common units, and the program may be suspended or discontinued at our discretion without prior notice.

For the year ended December 31, ~~2025~~2026, capital expenditures are expected to range between $~~625~~850.0 million to $~~775~~1.0 ~~million~~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.

73Working 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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~~Working~~Capital ~~capital~~expenditures. ~~Working~~Our ~~capital~~business is ancapital ~~indication~~intensive, ofrequiring ~~liquidity~~significant investment to maintain and ~~potential~~improve ~~needs~~existing ~~for~~facilities ~~short-term~~or ~~funding.~~to ~~Working~~develop ~~capital~~new ~~requirements~~midstream ~~are~~infrastructure. ~~driven~~Capital byexpenditures ~~changes~~include in(i) ~~accounts~~maintenance ~~receivable~~capital ~~and~~expenditures, ~~accounts~~which ~~payable~~include ~~and~~those ~~other~~expenditures ~~factors~~required ~~such~~to asmaintain ~~credit~~existing ~~extended~~operating ~~to,~~capacity and ~~the~~service ~~timing~~capability of ~~collections~~our ~~from~~assets, ~~our~~such ~~customers,~~as ~~and~~to ~~the~~replace ~~level~~system components and ~~timing~~equipment ofthat ~~our~~have ~~spending~~been ~~for~~subject ~~acquisitions,~~to ~~maintenance~~significant use over time, ~~and~~become ~~other~~obsolete ~~capital~~or ~~activities.~~reached Asthe end of ~~December 31,~~their ~~2024~~useful lives, weor ~~had~~to aremain ~~$155.5~~in ~~million~~compliance ~~working~~with ~~capital~~regulatory ~~surplus,~~or ~~which~~legal werequirements, ~~define~~and as(ii) ~~the~~expansion ~~amount~~capital byexpenditures, which ~~current~~include ~~assets~~expenditures ~~exceed~~to ~~current~~construct ~~liabilities.~~new Asmidstream ofinfrastructure ~~December 31,~~and ~~2024,~~expenditures ~~there~~incurred ~~was~~to ~~$2.0 billion~~reduce incosts, ~~effective~~increase ~~borrowing~~revenues, ~~capacity~~or ~~under~~increase ~~the~~system ~~RCF.~~throughput ~~Any~~or ~~outstanding~~capacity ~~commercial~~from ~~paper~~current ~~borrowings~~levels. ~~reduce~~Capital ~~the~~expenditures ~~effective~~in ~~borrowing~~the ~~capacity~~consolidated ~~under~~statements ~~the~~of ~~RCF~~cash asflows ~~WES~~reflect ~~Operating~~capital ~~maintains~~expenditures ~~availability~~on ~~under~~a ~~the~~cash ~~RCF~~basis, aswhen ~~support~~payments ~~for~~are ~~its~~made. ~~commercial~~Capital ~~paper~~incurred ~~program.~~is ~~See~~presented ~~Note 11—Selected~~on ~~Components~~an ofaccrual ~~Working~~basis. ~~Capital~~Acquisitions and ~~Note 13—Debt~~capital ~~and~~expenditures ~~Interest~~as ~~Expense~~presented in the ~~Notes~~consolidated tostatements ~~Consolidated~~of ~~Financial~~cash ~~Statements~~flows ~~under~~and ~~Part II,~~capital ~~Item 8~~incurred ofwere ~~this~~as ~~Form 10-K.~~follows:

Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.



	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

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	2024		2023
Acquisitions	$	443	$	877,746
Capital expenditures (1)	833,856		735,080
Capital incurred (1)	798,330		752,338

_________________________________________________________________________________________

(1)~~The~~For the years ended December 31, ~~2024~~2025 and ~~2023~~2024, included $1510.2 million and $1315.62 million, respectively, of capitalized interest.

Acquisitions for the year ended December 31, ~~2023~~2025, included the acquisition of ~~Meritage~~Aris. See Items Affecting the Comparability of Our Financial Results within this Item 7.

Capital expenditures ~~increased~~decreased by $98105.89 million for the year ended December 31, ~~2024~~2025, primarily due to ~~increases~~decreases of (i) $88216.38 million at the West Texas complex, primarily attributable to ~~engineering,~~construction ~~equipment,~~costs ~~and~~incurred ~~construction~~in ~~milestone~~2024 ~~payments~~associated ~~for~~with the North Loving ~~Plant,~~plant ~~(ii)~~that ~~$28.2~~was ~~million~~completed atin the ~~Powder~~first ~~River~~quarter ~~Basin complex primarily attributable to the acquisition~~ of ~~Meritage,~~2025 and (~~iii~~ii) $2423.23 million at the DBM water systems due to ~~increased~~decreased construction of certain water-disposal wells, equipment, facilities, and well-connect projects,. ~~and~~These decreases were offset partially by increases of (ivi) $863.25 million at the ~~Chipeta~~Powder River Basin complex primarily ~~related~~attributable to ~~expansion~~an ~~projects.~~increase ~~These~~in ~~increases~~construction ~~were~~of ~~offset~~facilities ~~partially~~and bywell-connect aprojects ~~decrease~~and of(ii) $5825.35 million at the DBM oil system related to aan ~~decrease~~increase in pipeline, oil ~~treating~~pumping, and ~~oil~~electrical ~~pumping~~distribution projects.

7469

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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

~~2024~~2025

~~2023~~2024

Net cash provided by (used in):

Operating activities

2,~~136~~222,~~860~~625

12,~~661~~136,~~334~~860

Investing activities

(391,~~168~~085,206)

(139,~~607,291~~168)

Financing activities

(1,~~280~~408,~~015~~392)

(671,~~912~~280,015)

Net increase (decrease) in cash and cash equivalents

~~817~~(270,~~677~~973)

~~(13~~817,~~869)~~677

Operating activities. Net cash provided by operating activities increased for the year ended December 31, ~~2024~~2025, primarily due to ~~higher cash operating income and~~ 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, ~~2024~~2025, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset-integrity projects at the ~~following:~~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.

~~•$833.9~~Net ~~million~~cash ofused 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.

~~•$18~~Financing activities.3 ~~million~~Net ofcash ~~increases~~used in financing activities for the year ended December 31, 2025, primarily included (i) distributions paid to ~~materials~~WES unitholders and ~~supplies~~noncontrolling ~~inventory~~interest owners, (ii) repayment of the total principal amount outstanding of the 3.950% Senior Notes due 2025 and ~~other;~~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.

~~•$582.7~~Net ~~million~~cash ofused ~~proceeds~~in ~~related~~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 ~~sale~~commercial paper program, (iii) retiring portions of ~~several~~certain ~~equity~~of ~~investments~~WES toOperating’s ~~third~~senior ~~parties;~~notes via open-market repurchases, and (iv) proceeds from the 5.450% Senior Notes due 2034 issued in August 2024.

~~•$206.2 million of proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party; and~~70

•$30.9 million of distributions received from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2023, primarily included the following:

•$877.7 million of cash paid, net of cash received, for the acquisition of Meritage;

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

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

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

Financing activities. Net cash used in financing activities for the year ended December 31, 2024, primarily included the following:

•$1,275.9 million of distributions paid to WES unitholders and noncontrolling interest owners;

•$610.3 million of net repayments under the commercial paper program;

•$143.9 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; and

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~~•$790~~Debt and credit facilities.3 As of December ~~million~~31, 2025, (i) the carrying value of ~~net~~outstanding ~~proceeds~~debt ~~from~~was $8.6 billion, (ii) the 5estimated future interest and RCF fee payments total $459.~~450~~8 million in 2026, (iii) the 4.650% Senior Notes due ~~2034~~2026 ~~issued~~are inclassified ~~August~~as ~~2024~~short-term debt on the consolidated balance sheet, ~~which~~and ~~will~~(iv) bethe ~~used~~effective toborrowing ~~repay~~capacity aunder ~~portion~~WES ofOperating’s ~~the~~$2.0 billion ~~maturing~~RCF 3is $2.~~100%~~0 billion. ~~Senior~~Any ~~Notes~~outstanding ~~due~~commercial ~~2025~~paper ~~and~~borrowings ~~3.950%~~reduce ~~Senior~~the ~~Notes~~effective ~~due~~borrowing ~~2025~~capacity ~~and~~under ~~for~~the ~~general~~RCF ~~partnership~~as ~~purposes,~~WES ~~including~~Operating maintains availability under the ~~funding~~RCF ofas ~~capital~~support ~~expenditures~~for its commercial paper program.

~~Net~~During ~~cash~~the ~~used~~year ended December 31, 2025, WES Operating (i) completed the public offerings of $600.0 million in ~~financing~~aggregate ~~activities~~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 ~~year~~3.100% ~~ended~~Senior ~~December~~Notes 31due 2025 on the maturity date of February 3, ~~2023~~2025, ~~primarily~~for ~~included~~$663.8 million. WES Operating repaid the ~~following:~~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.

~~•$1~~For additional information on our senior notes,~~495.0~~ ~~million~~RCF, ofand ~~repayments~~commercial ofpaper ~~outstanding~~program, ~~borrowings~~see ~~under~~Note 13—Debt in the ~~RCF;~~Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

~~•$1~~Finance leases. We have finance leases with third parties for equipment,~~008~~ vehicles, and an NGLs pipeline in Wyoming.9 As of December 31, 2025, we have future finance-lease payments of $8.8 million in 2026, and a total of ~~distributions~~$14.1 million ~~paid~~in years thereafter. See Note 14—Leases in the Notes to ~~WES~~Consolidated ~~unitholders~~Financial ~~and~~Statements ~~noncontrolling~~under ~~interest~~Part II, ~~owners;~~Item 8 of this Form 10-K.

~~•$259~~Asset retirement obligations.8 ~~million~~When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to ~~purchase~~the net present value of the settlement obligation, with an associated increase in property, plant, and ~~retire~~equipment. ~~portions~~Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of ~~certain~~settlement. As of ~~WES~~December 31, ~~Operating’s~~2025, ~~senior~~we ~~notes~~expect ~~via~~to ~~open-market~~incur ~~repurchases;~~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.

~~•$213~~Operating leases.1 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 toin ~~redeem~~2026, ~~the~~and a total ~~principal~~of ~~amount~~$133.2 million ~~outstanding~~in onyears ~~the~~thereafter. ~~Floating-Rate~~See ~~Senior~~Note 14—Leases in the Notes ~~due~~to ~~2023~~Consolidated atFinancial ~~par~~Statements ~~value;~~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 $~~134~~19.6 million for 2026, and a total of ~~unit~~$312.8 million ~~repurchases;~~in years thereafter.

~~•$1,120~~Pipeline commitments.0 ~~million~~We have transportation contracts with volume commitments on multiple pipelines through 2038. As of ~~borrowings~~December 31, ~~under~~2025, ~~the~~we ~~RCF~~have estimated future minimum-volume-commitment fees totaling $4.8 million in 2026, ~~which~~and ~~were~~a ~~used~~total ~~for~~of ~~general~~$263.1 million ~~partnership~~in ~~purposes;~~years thereafter.

~~•$740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes;~~71

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

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

Debt and credit facilities. As of December 31, 2024, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $385.1 million in 2025. In addition, we have $1.0 billion senior note borrowings due within the next year and, as of December 31, 2024, have $2.0 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF. 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, 2024, WES Operating (i) completed the public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034, (ii) purchased and retired $150.0 million of certain of its senior notes via open-market repurchases with cash from operations, and (iii) entered into an amendment to the RCF to exercise an option to extend the maturity date of the RCF from April 2028 to April 2029, for each extending lender. As of December 31, 2024, the 3.100% Senior Notes due 2025 and 3.950% Senior Notes due 2025 were classified as short-term debt on the consolidated balance sheet. Subsequent to December 31, 2024, WES Operating retired the 3.100% Senior Notes due 2025 on the maturity date of February 3, 2025.

For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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~~Finance~~Credit ~~lease liabilities~~risk. We ~~have~~bear ~~finance~~credit ~~leases~~risk ~~with~~through ~~third~~exposure ~~parties~~to ~~for~~non-payment ~~equipment~~or non-performance by our counterparties (e.g., ~~vehicles~~Occidental and other customers, financial institutions, and another ~~NGLs~~parties), ~~pipeline~~including inrisks ~~Wyoming.~~from Asa ofcustomer’s ~~December 31~~inability to satisfy payables to us for services rendered, ~~2024~~minimum-volume-commitment deficiency payments owed, weor ~~have~~volumes ~~future~~owed ~~finance~~pursuant to gas-~~lease~~ ~~payments~~or ofNGLs-imbalance ~~$11~~agreements.~~5 million~~ inWe ~~2025~~examine and amonitor ~~total~~the creditworthiness of ~~$27~~customers and may establish credit limits for customers.4 ~~million~~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 ~~years~~certain ~~thereafter~~circumstances, are exercising our contractual rights to request adequate assurance of performance.

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, 2024, we expect to incur asset retirement costs of $12.8 million in 2025 and a total of $370.2 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Operating leases. We have 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, 2024, we have future operating-lease payments of $60.5 million in 2025 and a total of $173.7 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Offload commitments. We have offload agreements with third parties providing firm-processing capacity through 2025. As of December 31, 2024, we have future minimum payments under offload agreements totaling $3.4 million for 2025.

Pipeline commitments. We have transportation contracts with volume commitments on multiple pipelines through 2035. As of December 31, 2024, we have estimated future minimum-volume-commitment fees totaling $15.0 million in 2025 and a total of $50.6 million in years thereafter.

Credit risk. We bear credit risk through exposure to non-payment or non-performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non-payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our contractual rights to request adequate assurance of performance.

We expect our exposure to the concentrated risk of non-payment or non-performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements.

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ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

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

Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:

Year Ended December 31,

thousands

~~2024~~2025

~~2023~~2024

~~2022~~2023

Net income (loss) attributable to WES

1,~~573~~180,~~571~~983

1,~~022~~573,~~216~~571

1,~~217~~022,~~103~~216

Limited partner interest in WES Operating not held by WES (1)

3223,~~156~~835

2032,~~922~~156

2420,~~899~~922

General and administrative expenses (2)

~~1,875~~720

21,~~943~~875

2,~~656~~943

Other income (expense), net

(~~252~~359)

(~~275~~252)

(45275)

Income taxes

82,734

Net income (loss) attributable to WES Operating

1,~~607~~207,~~358~~913

1,~~045~~607,~~812~~358

1,~~244~~045,~~620~~812

_________________________________________________________________________________________

(1)Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. ~~A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented.~~

(2)Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

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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

~~2024~~2025

~~2023~~2024

~~2022~~2023

WES net cash provided by operating activities

2,~~136~~222,~~860~~625

12,~~661~~136,~~334~~860

1,~~701~~661,~~426~~334

General and administrative expenses (1)

~~1,875~~720

21,~~943~~875

2,~~656~~943

Non-cash equity-based compensation expense

(~~581~~608)

(581)

(~~570~~581)

Changes in working capital

(29,~~198~~656)

(1529,~~226~~198)

(915,~~341~~226)

Other income (expense), net

(~~252~~359)

(~~275~~252)

(45275)

Income taxes

8—

WES Operating net cash provided by operating activities

2,~~108~~192,~~712~~722

12,~~648~~108,~~201~~712

1,~~694~~648,~~133~~201

WES net cash provided by (used in) financing activities

(1,~~280~~408,~~015~~392)

(671,~~912~~280,015)

(167,~~398,532~~912)

Distributions to WES unitholders (2)

1,~~246~~431,~~069~~024

~~978~~1,~~430~~246,069

~~735~~978,~~755~~430

Distributions to WES from WES Operating (3)

(1,~~246~~435,~~702~~970)

(1,~~119~~246,~~367~~702)

(1,~~219~~119,~~635~~367)

Increase (decrease) in outstanding checks

502,411

~~(52)~~50

~~103~~(52)

Unit repurchases

—

~~134,602~~—

~~487~~134,~~590~~602

Other

27,~~316~~337

1527,~~472~~316

915,~~326~~472

WES Operating net cash provided by (used in) financing activities

(1,~~253~~383,~~282~~590)

(581,~~827~~253,282)

(158,~~385,393~~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.

78Noncontrolling 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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Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third-party interest in Chipeta. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

CRITICAL ACCOUNTING ESTIMATES

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

Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s 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.

79Impairments 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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Impairments of equity investments. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. Management assesses its equity investments for impairment whenever events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary. When evidence of an other-than-temporary loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense.

We recognized long-lived asset and other impairments of $6.2 million and $52.9 million for the years ended December 31, 2024 and 2023, 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.

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.

We bear a limited degree of commodity-price risk with respect to settlement of natural-gas and NGLs imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers, and for instances where actual liquids recovery or fuel usage varies from contractually stipulated amounts. Natural-gas and NGLs volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and generally reflect market-index prices. Other natural-gas and NGLs volumes owed to or by us are valued at our weighted-average cost as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the settlement timing of the imbalances. See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K.

Interest-rate risk. The Federal Open Market Committee ~~increased~~lowered its target range ~~four times~~ for the federal funds rate three times in ~~2023~~2024 and decreased ~~its~~it ~~target~~twice ~~range three times~~ during the year ended December 31, ~~2024~~2025. Any future increases in the federal funds rate likely will result in an increase in financing costs. As of December 31, ~~2024~~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, ~~2024~~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			8378
Western Midstream Partners, LP			8479
Reports of Independent Registered Public Accounting Firm			8479
Financial Statements			8883
Consolidated Statements of Operations for the years ended December 31, 2024, 2023, and 2022			88
Consolidated Statements of Operations for the years ended December 31, 2025, 2024, and 2023			83
Consolidated Balance Sheets as of December 31, 2024 and 2023			89
Consolidated Balance Sheets as of December 31, 2025 and 2024			84
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2024, 2023, and 2022			90
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, 2024, 2023, and 2022			91
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023			86
Western Midstream Operating, LP			9287
Report of Independent Registered Public Accounting Firm			9287
Financial Statements			9489
Consolidated Statements of Operations for the years ended December 31, 2024, 2023, and 2022			94
Consolidated Statements of Operations for the years ended December 31, 2025, 2024, and 2023			89
Consolidated Balance Sheets as of December 31, 2024 and 2023			95
Consolidated Balance Sheets as of December 31, 2025 and 2024			90
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2024, 2023, and 2022			96
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, 2024, 2023, and 2022			97
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023			92
Notes to Consolidated Financial Statements			9893
Note 1. Summary of Significant Accounting Policies and Basis of Presentation			9893
Note 2. Revenue from Contracts with Customers			~~107~~102
Note 3. Acquisitions and Divestitures			~~109~~104
Note 4. Partnership Distributions			~~112~~107
Note 5. Equity and Partners’ Capital			~~113~~109
Note 6. Related-Party Transactions			~~115~~110
Note 7. Equity Investments			~~119~~113
Note 8. Income Taxes			~~121~~116
Note 9. Property, Plant, and Equipment			~~122~~118
Note 10. Goodwill and Other Intangibles			~~123~~119
Note 11. Selected Components of Working Capital			~~124~~120
Note 12. Asset Retirement Obligations			~~125~~121
Note 13. Debt and Interest Expense			~~126~~122
Note 14. Leases			~~129~~125
Note 15. Equity-Based Compensation			~~131~~127
Note 16. Commitments and Contingencies			~~133~~129
Note 17. Reportable Segment			~~133~~130
Note 18. Subsequent Event			132

8277

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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, ~~2024~~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, ~~2024~~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, ~~2024~~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 2618, ~~2025~~2026

8378

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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, ~~2024~~2025 and ~~2023~~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, ~~2024~~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, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, ~~2024~~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, ~~2024~~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 2618, ~~2025~~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.

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be recoverable. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset.

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

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

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

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

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

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

/s/ KPMG LLP

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

Houston, Texas

February 2618, ~~2025~~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, ~~2024~~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, ~~2024~~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, ~~2024~~2025 and ~~2023~~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, ~~2024~~2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 2618, ~~2025~~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.

/s/ KPMG LLP

Houston, Texas

February 2618, ~~2025~~2026

8782

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WESTERN MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31,

thousands except per-unit amounts

~~2024~~2025

~~2023~~2024

~~2022~~2023

Revenues and other

Service revenues – fee based

3,~~248~~453,~~262~~052

23,~~768~~248,~~757~~262

2,~~602~~768,~~053~~757

Service revenues – product based

~~215~~193,~~776~~866

~~191~~215,~~727~~776

~~249~~191,~~692~~727

Product sales

~~140~~194,~~100~~681

~~145~~140,~~024~~100

~~399~~145,~~023~~024

Other

1,~~085~~804

~~968~~1,085

~~953~~968

Total revenues and other (1)

3,~~605~~843,~~223~~403

3,~~106~~605,~~476~~223

3,~~251~~106,~~721~~476

Equity income, net – related parties

~~112~~85,~~385~~788

~~152~~112,~~959~~385

~~183~~152,~~483~~959

Operating expenses

Cost of product

~~172~~206,~~251~~978

~~164~~172,~~598~~251

~~420~~164,~~900~~598

Operation and maintenance

~~880~~915,~~568~~896

~~762~~880,~~530~~568

~~654~~762,~~566~~530

General and administrative

~~271~~398,~~526~~922

~~232~~271,~~632~~526

~~194~~232,~~017~~632

Property and other taxes

6269,~~668~~342

5662,~~458~~668

7856,~~559~~458

Depreciation and amortization

~~650~~710,~~428~~778

~~600~~650,~~668~~428

~~582~~600,~~365~~668

Long-lived asset and other impairments (2)

6,206

52,884

20,585

Long-lived asset and other impairments

14,760

6,206

52,884

Total operating expenses (3)

2,043,647

1,869,770

1,950,992

Total operating expenses (2)

2,316,676

2,043,647

1,869,770

Gain (loss) on divestiture and other, net

~~296~~(11,~~771~~113)

~~(10~~296,~~102)~~771

~~103~~(10,~~676~~102)

Operating income (loss)

1,~~970~~601,~~732~~402

1,~~379~~970,~~563~~732

1,~~587~~379,~~888~~563

Interest expense

(~~378~~390,~~513~~490)

(~~348~~378,~~228~~513)

(~~333~~348,~~939~~228)

Gain (loss) on early extinguishment of debt

~~5,403~~—

155,~~378~~403

9115,378

Other income (expense), net

3116,~~741~~629

531,~~679~~741

15,~~603~~679

Income (loss) before income taxes

1,~~629~~227,~~363~~541

1,~~052~~629,~~392~~363

1,~~255~~052,~~643~~392

Income tax expense (benefit)

1815,~~111~~086

418,~~385~~111

4,~~187~~385

Net income (loss)

1,~~611~~212,~~252~~455

1,~~048~~611,~~007~~252

1,~~251~~048,~~456~~007

Net income (loss) attributable to noncontrolling interests

3731,~~681~~472

2537,~~791~~681

3425,~~353~~791

Net income (loss) attributable to Western Midstream Partners, LP

1,~~573~~180,~~571~~983

1,~~022~~573,~~216~~571

1,~~217~~022,~~103~~216

Limited partners’ interest in net income (loss):

Net income (loss) attributable to Western Midstream Partners, LP

1,~~573~~180,~~571~~983

1,~~022~~573,~~216~~571

1,~~217~~022,~~103~~216

General partner interest in net (income) loss

(3626,~~604~~485)

(2336,~~684~~604)

(2723,~~541~~684)

Limited partners’ interest in net income (loss) (4)

1,536,967

998,532

1,189,562

Limited partners’ interest in net income (loss) (3)

1,154,498

1,536,967

998,532

Net income (loss) per common unit – basic (4)

4.04

2.61

3.01

Net income (loss) per common unit – basic (3)

2.99

4.04

2.61

Net income (loss) per common unit – diluted (4)

4.02

2.60

3.00

Net income (loss) per common unit – diluted (3)

2.98

4.02

2.60

Weighted-average common units outstanding – basic (4)

380,397

383,028

394,951

Weighted-average common units outstanding – basic (3)

386,074

380,397

383,028

Weighted-average common units outstanding – diluted (4)

382,455

384,408

396,236

Weighted-average common units outstanding – diluted (3)

387,880

382,455

384,408

_________________________________________________________________________________________

(1)Total revenues and other includes related-party amounts of $2.23 billion, $12.82 billion, and $1.8 billion for the years ended December 31, ~~2024~~2025, ~~2023~~2024, and ~~2022~~2023, respectively. See Note 6.

(2)~~See~~Total ~~Note 7~~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 96.

(3)Total operating expenses includes related-party amounts of $(56.5) million, $(68.0) million, and $(18.0) million for the years ended December 31, 2024, 2023, and 2022, respectively, all primarily related to changes in imbalance positions. See Note 65.

(4)See Note 5.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

December 31,

thousands except number of units

~~2024~~2025

~~2023~~2024

ASSETS

Current assets

Cash and cash equivalents

1819,~~090,464~~491

~~272~~1,~~787~~090,464

Accounts receivable, net

~~701~~773,~~838~~197

~~666~~701,~~637~~838

Other current assets

5464,~~888~~253

5254,~~986~~888

Total current assets

1,~~847~~656,~~190~~941

~~992~~1,~~410~~847,190

Property, plant, and equipment

Cost

1517,~~509~~648,~~910~~375

1415,~~945~~509,~~431~~910

Less accumulated depreciation

56,~~795~~427,~~301~~467

5,~~290~~795,~~415~~301

Net property, plant, and equipment

911,~~714~~220,~~609~~908

9,~~655~~714,~~016~~609

Goodwill

4353,~~783~~257

4,783

Other intangible assets

~~649~~913,~~740~~758

~~681~~649,~~408~~740

Equity investments

~~541~~504,~~435~~859

~~904~~541,~~535~~435

Other assets (1)

387,028

233,455

Other assets

348,697

387,028

Total assets (2)

13,144,785

12,471,607

Total assets (1)

14,998,420

13,144,785

LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL

Current liabilities

Accounts and imbalance payables

~~312~~319,~~945~~170

~~362~~312,~~451~~945

Short-term debt

1448,~~011,032~~825

~~617~~1,~~748~~011,032

Accrued ad valorem taxes

3860,~~319~~114

6138,~~285~~319

Accrued liabilities

~~329~~408,~~398~~375

~~262~~329,~~572~~398

Total current liabilities

1,~~691~~236,~~694~~484

1,~~304~~691,~~056~~694

Long-term liabilities

Long-term debt

68,~~926~~195,~~647~~170

76,~~283~~926,~~556~~647

Deferred income taxes

29111,~~679~~277

1529,~~468~~679

Asset retirement obligations

~~370~~427,~~195~~858

~~359~~370,~~185~~195

Other liabilities

~~751~~864,~~400~~509

~~480~~751,~~212~~400

Total long-term liabilities

89,~~077~~598,~~921~~814

8,~~138~~077,~~421~~921

Total liabilities (3)

9,769,615

9,442,477

Total liabilities (2)

10,835,298

9,769,615

Equity and partners’ capital

Common units (380,556,643 and 379,519,983 units issued and outstanding at December 31, 2024 and 2023, respectively)

3,224,802

2,894,231

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, 2024 and 2023)

10,803

3,193

General partner units (9,060,641 units issued and outstanding at December 31, 2025 and 2024)

4,624

10,803

Total partners’ capital

34,~~235~~021,~~605~~230

23,~~897~~235,~~424~~605

Noncontrolling interests

~~139~~141,~~565~~892

~~131~~139,~~706~~565

Total equity and partners’ capital

34,~~375~~163,~~170~~122

3,~~029~~375,~~130~~170

Total liabilities, equity, and partners’ capital

1314,~~144~~998,~~785~~420

1213,~~471~~144,~~607~~785

________________________________________________________________________________________

(1)~~Other~~Total assets includes related-party amounts of $5946.54 million and $5991.71 million ~~of NGLs line-fill inventory~~ as of December 31, ~~2024~~2025 and ~~2023~~2024, respectively., ~~Other~~which ~~assets~~includes ~~also~~related-party ~~includes~~Accounts receivable, net of $~~110~~407.39 million and $96401.3 million ~~of materials and supplies inventory~~ as of December 31, ~~2024~~2025 and ~~2023~~2024, respectively. See Note 6.

(2)Total ~~assets~~liabilities includes related-party amounts of $~~991~~666.19 million and $1529.37 ~~billion~~million as of December 31, ~~2024~~2025 and ~~2023~~2024, respectively, which includes related-party Accounts ~~receivable,~~and ~~net~~imbalance payables of $~~401~~20.36 million ~~and $358.1 million~~ as of December 31, ~~2024~~2025 and ~~2023, respectively~~2024. See Note 6.

(3)Total liabilities includes related-party amounts of $529.7 million and $378.8 million as of December 31, 2024 and 2023, respectively. See Note 6.

See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL

	Partners’ Capital
thousands	CommonUnits		General PartnerUnits		NoncontrollingInterests		~~Total~~		Total
Balance at December 31, 2021	$	2,966,955	$	(8,882)	$	137,687	$	3,095,760
Balance at December 31, 2022	$	2,969,604	$	2,105	$	136,406			$	3,108,115
Net income (loss)	1998,~~189,562~~532		2723,~~541~~684		3425,~~353~~791		~~1,251,456~~		1,048,007
Distributions to Chipeta noncontrolling interest owner	—		—		(107,~~736~~641)		~~(10,736)~~		(7,641)
Distributions to noncontrolling interest owner of WES Operating	—		—		(2422,~~898~~850)		~~(24,898)~~		(22,850)
Distributions to Partnership unitholders	(~~719~~955,~~201~~834)		(1622,~~554~~596)		—		~~(735,755)~~		(978,430)
Unit repurchases (1)	(~~487~~134,~~590~~602)		—		—		~~(487,590)~~		(134,602)
Contributions of equity-based compensation from Occidental	2,277		—		—		2,277
Equity-based compensation expense	32,005		—		—				32,005
Equity-based compensation expense	25,506		—		—		25,506
Other	(15,474)		—		—				(15,474)
Net contributions from (distributions to) related parties	1,423		—		—		1,423
Balance at December 31, 2023	$	2,894,231	$	3,193	$	131,706			$	3,029,130
Other	(9,328)		—		—		(9,328)
Net income (loss)	1,536,967		36,604		37,681				1,611,252
Balance at December 31, 2022	$	2,969,604	$	2,105	$	136,406	$	3,108,115
Distributions to Chipeta noncontrolling interest owner	—		—		(4,372)				(4,372)
Net income (loss)	998,532		23,684		25,791		1,048,007
Distributions to noncontrolling interest owner of WES Operating	—		—		(25,450)				(25,450)
Distributions to Chipeta noncontrolling interest owner	—		—		(7,641)		(7,641)
Distributions to Partnership unitholders	(1,217,075)		(28,994)		—				(1,246,069)
Distributions to noncontrolling interest owner of WES Operating	—		—		(22,850)		(22,850)
Equity-based compensation expense	37,994		—		—				37,994
Distributions to Partnership unitholders	(955,834)		(22,596)		—		(978,430)
Other	(27,315)		—		—				(27,315)
Unit repurchases (1)	(134,602)		—		—		(134,602)
Balance at December 31, 2024	$	3,224,802	$	10,803	$	139,565			$	3,375,170
Equity-based compensation expense	32,005		—		—		32,005
Net income (loss)	1,154,498		26,485		31,472				1,212,455
Other	(15,474)		—		—		(15,474)
Acquisition-related issuance of units	1,005,017		—		—				1,005,017
Balance at December 31, 2023	$	2,894,231	$	3,193	$	131,706	$	3,029,130
Distributions to Chipeta noncontrolling interest owner	—		—		(2,095)				(2,095)
Net income (loss)	1,536,967		36,604		37,681		1,611,252
Distributions to noncontrolling interest owner of WES Operating	—		—		(29,534)				(29,534)
Distributions to Chipeta noncontrolling interest owner	—		—		(4,372)		(4,372)
Distribution to Partnership unitholders	(1,398,360)		(32,664)		—				(1,431,024)
Distributions to noncontrolling interest owner of WES Operating	—		—		(25,450)		(25,450)
Equity-based compensation expense	50,803		—		—				50,803
Distributions to Partnership unitholders	(1,217,075)		(28,994)		—		(1,246,069)
Other	(20,154)		—		2,484				(17,670)
Equity-based compensation expense	37,994		—		—		37,994
Balance at December 31, 2025	$	4,016,606	$	4,624	$	141,892			$	4,163,122
Other	(27,315)		—		—		(27,315)
Balance at December 31, 2024	$	3,224,802	$	10,803	$	139,565	$	3,375,170

_________________________________________________________________________________________

(1)See Note 5 and Note 6.

See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,

thousands

~~2024~~2025

~~2023~~2024

~~2022~~2023

Cash flows from operating activities

Net income (loss)

1,~~611~~212,~~252~~455

1,~~048~~611,~~007~~252

1,~~251~~048,~~456~~007

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization

~~650~~710,~~428~~778

~~600~~650,~~668~~428

~~582~~600,~~365~~668

Long-lived asset and other impairments

614,~~206~~760

526,~~884~~206

2052,~~585~~884

Non-cash equity-based compensation expense

3750,~~994~~803

3237,~~005~~994

2732,~~783~~005

Deferred income taxes

143,~~211~~944

114,~~044~~211

1,~~999~~044

Accretion and amortization of long-term obligations, net

96,~~238~~945

89,~~151~~238

78,~~142~~151

Equity income, net – related parties

(~~112~~85,~~385~~788)

(~~152~~112,~~959~~385)

(~~183~~152,~~483~~959)

Distributions from equity-investment earnings – related parties

~~111~~90,~~386~~973

~~155~~111,~~169~~386

~~186~~155,~~153~~169

(Gain) loss on divestiture and other, net

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