Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K.
Discussion of 2023 items, and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2024, as filed with the SEC on February 26, 2025, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.
The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.1% partnership interest in WES Operating, as of December 31, 2025. Amounts attributable to noncontrolling interests presented in this Item 7 consist of (i) the 25% third-party interest in Chipeta for all periods presented, and only for natural-gas assets for throughput attributable to WES, and (ii) the 1.9%, 2.0%, and 2.0% limited partner interest in WES Operating as of December 31, 2025, 2024, and 2023, respectively, owned by an Occidental subsidiary. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental.
EXECUTIVE SUMMARY
We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering, transporting, recycling, treating, supplying, and disposing of produced water. In our capacity as a natural - gas processor, we also buy and sell residue, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We own or have investments in assets located in Texas, New Mexico, and the Rocky Mountains (Colorado, Utah, and Wyoming). As of December 31, 2025, our assets and investments consisted of the following:
Wholly
Owned and
Operated Operated
Interests Equity
Interests
Gathering systems
13 2 1
Treating facilities 43 3 —
Processing plants/trains
27 3 1
Produced-water gathering, treating, recycling, and disposal systems 8 — —
NGLs pipelines 3 — 4
Natural - gas pipelines
6 — 1
Crude - oil pipelines
2 1 1
Significant financial and operational events during the year ended December 31, 2025, included the following:
• On October 15, 2025, we closed on the acquisition of Aris by merger in an equity-and-cash transaction. See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information.
• WES Operating completed the public offerings of $1.2 billion in aggregate principal amount of Senior Notes. Net proceeds from these public offerings (i) will be used to repay the 4.650% Senior Notes due 2026, (ii) were used to repay amounts outstanding under its commercial paper program (including borrowings incurred to fund the cash consideration of the Aris acquisition), and (iii) will be used for general partnership purposes, including the funding of capital expenditures. See Debt and Credit Facilities within this Item 7 for additional information.
52
Table of Contents
• WES Operating retired the total principal amount outstanding of the 3.100% Senior Notes due 2025 at par value during the first quarter of 2025 and the 3.950% Senior Notes due 2025 at par value during the second quarter of 2025.
• Our fourth-quarter 2025 per-unit distribution is unchanged from the third-quarter 2025 per-unit distribution of $0.910.
• We completed the start-up of the North Loving plant in late-February 2025, increasing gas processing capacity at the West Texas complex by 250 MMcf/d to a total of 2,190 MMcf/d.
The following table provides additional information on throughput for the periods presented below:
Year Ended December 31,
2025 2024 Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin 2,042 1,871 9 %
DJ Basin 1,470 1,436 2 %
Powder River Basin 437 456 (4) %
Equity investments 550 517 6 %
Other 905 946 (4) %
Total throughput for natural-gas assets 5,404 5,226 3 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin 258 243 6 %
DJ Basin 97 92 5 %
Powder River Basin 27 25 8 %
Equity investments 104 144 (28) %
Other 38 37 3 %
Total throughput for crude-oil and NGLs assets 524 541 (3) %
Throughput for produced-water assets (MBbls/d)
Delaware Basin 1,608 1,147 40 %
Total throughput for produced-water assets 1,608 1,147 40 %
53
Table of Contents
OUR OPERATIONS
Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, produced water, and water solutions. We gather natural gas from individual wells or production facilities located near our gathering systems, and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather, transport, recycle, treat, supply, and dispose of produced water.
We operate in Texas, New Mexico, Colorado, Utah, and Wyoming, with a substantial portion of our business concentrated in West Texas, New Mexico, and the Rocky Mountains. For example, for the year ended December 31, 2025, and excluding the impact of equity investments, our West Texas / New Mexico and DJ Basin assets provided (i) 58% and 29%, respectively, of Total revenues and other, (ii) 42% and 30%, respectively, of our throughput for natural-gas assets, (iii) 61% and 23%, respectively, of our throughput for crude-oil and NGLs assets, and (iv) all of our throughput for produced-water assets.
For the year ended December 31, 2025, and excluding the impact of equity investments, 60% of Total revenues and other, 36% of our throughput for natural-gas assets, 91% of our throughput for crude-oil and NGLs assets, and 61% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts.
For the year ended December 31, 2025, and excluding the impact of equity investments, 97% of our wellhead natural-gas volume and 100% of our crude-oil and produced-water throughput were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) actual recoveries differ from contractual recoveries under certain of our processing agreements or (ii) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities and skim oil that is recovered during the produced-water gathering and disposal process.
We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to alter drilling or production schedules in certain areas, which could cause variability in the volumes of hydrocarbons available to our systems. We also bear limited commodity-price risk through the settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K.
HOW WE EVALUATE OUR OPERATIONS
Our management relies on certain metrics to analyze our financial and operational results, including (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7).
Throughput . Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities. Our success in maintaining or increasing throughput is impacted by (i) the successful drilling of new wells by producers that are dedicated to our systems, (ii) recompletions of existing wells connected to our systems, (iii) our ability to secure volumes from new wells drilled on non-dedicated acreage, and (iv) our ability to attract natural-gas, crude-oil, NGLs, produced-water, or water-solutions volumes currently serviced by our competitors.
54
Table of Contents
Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services.
General and administrative expenses . To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods, the annual budget, and other companies in the midstream industry.
Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures associated with growth and maintenance projects are closely monitored. Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved.
ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS
Our historical results of operations and cash flows for the periods presented may not be comparable to future or historical results of operations or cash flows for the reasons described below. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.
Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 18—Subsequent Event in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. In addition, certain of our natural-gas processing agreements provide our producer customers the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows. See Risk Factors under Part I, Item 1A of this Form 10-K.
Acquisitions and divestitures. During the fourth quarter of 2025, we closed on the acquisition of Aris by merger in a transaction valued at $2.0 billion, including the cash and equity merger consideration, Aris’s outstanding debt of $80.0 million in revolving credit facility borrowings that were repaid at closing, and $500.0 million in principal amount of senior notes. Based on Aris shareholder consideration elections, we issued 26.6 million common units and paid $415.0 million in cash, funded with borrowings under the commercial paper program, in exchange for all issued and outstanding shares of Aris common stock.
During the second quarter of 2024, we closed on the sale of our 33.75% interest in the Marcellus Interest systems for proceeds of $206.2 million, resulting in a net gain on sale of $63.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations.
During the first quarter of 2024, we closed on the sale of the following equity investments to third parties: (i) the 25.00% interest in Mont Belvieu JV, (ii) the 20.00% interest in Whitethorn LLC, (iii) the 15.00% interest in Panola, and (iv) the 20.00% interest in Saddlehorn. The combined proceeds received in the first quarter of 2024 of $588.6 million includes $5.9 million in pro-rata distributions through closing, resulting in a net gain on sale of $239.7 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations.
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
55
Table of Contents
RESULTS OF OPERATIONS
OPERATING RESULTS
The following tables and discussion present a summary of our results of operations:
Year Ended December 31,
thousands 2025 2024
Total revenues and other (1)
$ 3,843,403 $ 3,605,223
Equity income, net – related parties 85,788 112,385
Total operating expenses (1)
2,316,676 2,043,647
Gain (loss) on divestiture and other, net (11,113) 296,771
Operating income (loss) 1,601,402 1,970,732
Interest expense (390,490) (378,513)
Gain (loss) on early extinguishment of debt — 5,403
Other income (expense), net 16,629 31,741
Income (loss) before income taxes 1,227,541 1,629,363
Income tax expense (benefit) 15,086 18,111
Net income (loss) 1,212,455 1,611,252
Net income (loss) attributable to noncontrolling interests 31,472 37,681
Net income (loss) attributable to Western Midstream Partners, LP (2)
$ 1,180,983 $ 1,573,571
_________________________________________________________________________________________
(1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, NGLs, and water solutions volumes to related parties. Total operating expenses includes amounts charged by related parties for services received. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2) For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2025” refer to the comparison of the year ended December 31, 2025, to the year ended December 31, 2024.
Discussion of 2023 items and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations , which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2024, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com .
56
Table of Contents
Throughput
Year Ended December 31,
2025 2024 Inc/(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation 375 453 (17) %
Processing 4,479 4,256 5 %
Equity investments (1)
550 517 6 %
Total throughput 5,404 5,226 3 %
Throughput attributable to noncontrolling interests 178 174 2 %
Total throughput attributable to WES for natural - gas assets
5,226 5,052 3 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation 420 397 6 %
Equity investments (1)
104 144 (28) %
Total throughput 524 541 (3) %
Throughput attributable to noncontrolling interests 10 11 (9) %
Total throughput attributable to WES for crude - oil and NGLs assets
514 530 (3) %
Throughput for produced-water assets (MBbls/d)
Gathering, disposal, and water solutions 1,608 1,147 40 %
Throughput attributable to noncontrolling interests 30 23 30 %
Total throughput attributable to WES for produced - water assets (2)
1,578 1,124 40 %
_________________________________________________________________________________________
(1) Represents our share of average throughput for investments accounted for under the equity method of accounting.
(2) Water solutions volumes include groundwater and gathered produced water that is treated and recycled.
Natural-gas assets
Total throughput attributable to WES for natural - gas assets increased by 174 MMcf/d for the year ended December 31, 2025, primarily due to (i) higher volumes at the West Texas, DJ Basin, and Chipeta complexes due to increased production in the areas and (ii) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline beginning in November 2024. These increases were offset partially by (i) lower volumes at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024, (ii) lower volumes at the Springfield gas-gathering system due to decreased production in the area, and (iii) lower volumes at the Mi Vida plant.
Crude-oil and NGLs assets
Total throughput attributable to WES for crude - oil and NGLs assets decreased by 16 MBbls/d for the year ended December 31, 2025, primarily due to (i) the divestiture of Whitethorn LLC and Saddlehorn in the first quarter of 2024 and (ii) lower volumes on the TEP pipeline. These decreases were offset partially by higher volumes at the DBM oil system due to increased production in the area.
Produced-water assets
Total throughput attributable to WES for produced - water assets increased by 454 MBbls/d for the year ended December 31, 2025, due to (i) the acquisition of Aris and (ii) higher production.
57
Table of Contents
Revenues
Year Ended December 31,
thousands except percentages and per-unit amounts
2025 2024 Inc/(Dec)
Service revenues – fee based $ 3,453,052 $ 3,248,262 6 %
Other revenues from customers
Service revenues – product based $ 193,866 $ 215,776 (10) %
Product sales 194,681 140,100 39 %
Total other revenues from customers
$ 388,547 $ 355,876 9 %
Per - unit gross average sales price:
Natural gas (per Mcf) $ 0.90 $ 0.29 NM
NGLs (per Bbl) 25.48 28.62 (11) %
_________________________________________________________________________________________
NM — Not meaningful
Service revenues – fee based
Service revenues – fee based increased by $204.8 million for the year ended December 31, 2025, primarily due to increases of (i) $105.6 million at the DBM water systems due to the acquisition of Aris and increased throughput, partially offset by a change in contract terms effective January 1, 2025, (ii) $98.5 million at the West Texas complex primarily due to increased throughput, partially offset by decreased deficiency fees on certain contracts with throughput minimums, (iii) $32.6 million at the DBM oil system due to increased throughput, higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2025, and deficiency fees on certain contracts with increasing throughput minimums, and (iv) $10.1 million at the DJ Basin complex primarily due to increased throughput. These increases were offset partially by decreases of (i) $32.4 million at the Springfield systems due to decreased throughput and lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, (ii) $18.7 million at the DJ Basin oil system due to lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput, and (iii) $11.0 million at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024.
Other revenues from customers
Other revenues from customers increased by $32.7 million for the year ended December 31, 2025, primarily due to (i) $52.8 million at the West Texas complex due to increased volumes sold and net average prices and (ii) $29.1 million at the DBM water systems due to the acquisition of Aris and increased volumes sold. These increases were offset partially by a decrease of $35.5 million at the DJ Basin complex primarily due to lower volumes sold and average prices.
58
Table of Contents
Equity Income, Net – Related Parties
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
Equity income, net – related parties $ 85,788 $ 112,385 (24) %
Equity income, net – related parties decreased by $26.6 million for the year ended December 31, 2025, primarily due to decreases of $7.6 million and $7.0 million at TEP and Mi Vida, respectively.
Cost of Product and Operation and Maintenance Expenses
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
Natural-gas purchases
$ 33,941 $ 10,586 NM
NGLs purchases 240,109 252,591 (5) %
Other (67,072) (90,926) 26 %
Cost of product 206,978 172,251 20 %
Operation and maintenance 915,896 880,568 4 %
Total Cost of product and Operation and maintenance expenses $ 1,122,874 $ 1,052,819 7 %
Natural-gas purchases
Natural-gas purchases increased by $23.4 million for the year ended December 31, 2025, primarily due to (i) higher average prices at the West Texas complex and (ii) increased purchases at the Chipeta complex.
NGLs purchases
NGLs purchases decreased by $12.5 million for the year ended December 31, 2025, primarily due to a decrease of $17.6 million at the DJ Basin complex due to lower purchased volumes and average prices, partially offset by an increase of $11.1 million due to the acquisition of Aris.
Other items
Other items increased by $23.9 million for the year ended December 31, 2025, primarily due to changes in imbalance positions at the West Texas and Powder River Basin complexes.
Operation and maintenance expense
Operation and maintenance expense increased by $35.3 million for the year ended December 31, 2025, primarily due to increases of (i) $48.3 million related to the acquisition of Aris, (ii) $12.4 million in utility expense, and (iii) $6.2 million in land-related costs. These amounts were offset partially by decreases of (i) $7.7 million in chemicals and treating services, (ii) $7.6 million in contract labor and consulting costs, (iii) $6.2 million in mechanical-integrity costs, and (iv) $6.1 million in regulatory and environmental expense.
59
Table of Contents
Other Operating Expenses
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
General and administrative $ 398,922 $ 271,526 47 %
Property and other taxes 69,342 62,668 11 %
Depreciation and amortization 710,778 650,428 9 %
Long-lived asset and other impairments 14,760 6,206 138 %
Total other operating expenses $ 1,193,802 $ 990,828 20 %
General and administrative expenses
General and administrative expenses increased by $127.4 million for the year ended December 31, 2025, primarily due to $120.5 million in acquisition-related expenses associated with the Aris transaction, including $104.6 million in severance payments and $15.9 million in professional services for financial advisory, legal, and other professional fees.
Depreciation and amortization expense
Depreciation and amortization expense increased by $60.4 million for the year ended December 31, 2025, primarily due to (i) $31.2 million in capital projects being placed into service at the West Texas complex and (ii) $21.5 million related to the acquisition of Aris.
Long-lived asset and other impairment expense
Long - lived asset and other impairment expense increased by $8.6 million for the year ended December 31, 2025, primarily due to a $10.8 million impairment at the Granger complex.
Interest Expense
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
Long-term and short-term debt $ (387,493) $ (377,850) 3 %
Finance lease liabilities (2,182) (2,573) (15) %
Commitment fees and amortization of debt-related costs (11,001) (13,305) (17) %
Capitalized interest 10,186 15,215 (33) %
Interest expense $ (390,490) $ (378,513) 3 %
Interest expense increased by $12.0 million for the year ended December 31, 2025, primarily due to increases of (i) $28.2 million of interest incurred on the 5.450% Senior Notes due 2034 that were issued during the third quarter of 2024, (ii) $6.4 million of interest incurred on the 7.250% Senior Notes due 2030 that were assumed as part of the acquisition of Aris during the fourth quarter of 2025, and (iii) $5.0 million due to lower capitalized interest. These increases were offset partially by a decrease of $30.0 million due to senior note repayments during 2025. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.
60
Table of Contents
Other Income (Expense), Net
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
Other income (expense), net $ 16,629 $ 31,741 (48) %
Other income (expense), net decreased by $15.1 million for the year ended December 31, 2025, primarily due to lower interest income earned on cash investments throughout 2025.
Income Tax Expense (Benefit)
Year Ended December 31,
thousands except percentages 2025 2024 Inc/(Dec)
Income (loss) before income taxes $ 1,227,541 $ 1,629,363 (25) %
Income tax expense (benefit) 15,086 18,111 (17) %
Effective tax rate 1 % 1 % — %
We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. Income tax expense decreased by $3.0 million for the year ended December 31, 2025, primarily due to Texas margin tax liability and federal income tax on activities operated through corporate entities. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
61
Table of Contents
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
Adjusted Gross Margin. We define Adjusted Gross Margin attributable to Western Midstream Partners, LP (“Adjusted Gross Margin”) as total revenues and other (less reimbursements for electricity - related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product. We believe Adjusted Gross Margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted Gross Margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers.
Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) income tax benefit, (v) other income, (vi) other items impacting comparability with our core operating performance, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following:
• our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis;
• the ability of our assets to generate cash flow to make distributions; and
• the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities.
Free Cash Flow. We define “Free Cash Flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free Cash Flow an appropriate metric for assessing capital discipline, cost efficiency, and balance - sheet strength. Although Free Cash Flow is the metric used to assess our ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period. Instead, Free Cash Flow represents the amount of cash that is available in aggregate for distributions, debt repayments, and other general partnership purposes.
Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted Gross Margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA. The GAAP measure that is most directly comparable to Free Cash Flow is net cash provided by operating activities. Our non - GAAP financial measures (i) should not be considered as alternatives to the comparable GAAP measures or any other measure of financial performance presented in accordance with GAAP, (ii) have important limitations as analytical tools because they exclude some, but not all, items that affect the comparable GAAP measures, (iii) should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP, and (iv) may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.
Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences, and incorporating this knowledge into its decision - making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results.
62
Table of Contents
The following tables present reconciliations of the GAAP measure to our non-GAAP measures:
Year Ended December 31,
thousands 2025 2024
Reconciliation of Gross margin to Adjusted Gross Margin
Total revenues and other $ 3,843,403 $ 3,605,223
Less:
Cost of product 206,978 172,251
Depreciation and amortization 710,778 650,428
Gross margin 2,925,647 2,782,544
Add:
Distributions from equity investments 122,364 142,236
Depreciation and amortization 710,778 650,428
Less:
Reimbursed electricity-related charges recorded as revenues 125,551 117,906
Adjusted Gross Margin attributable to noncontrolling interests 83,681 80,509
Adjusted Gross Margin
$ 3,549,557 $ 3,376,793
To facilitate investor and industry analysis, we also disclose per-Mcf Adjusted Gross Margin for natural-gas assets, per-Bbl Adjusted Gross Margin for crude-oil and NGLs assets, and per-Bbl Adjusted Gross Margin for produced-water assets .
Year Ended December 31,
thousands except per-unit amounts 2025 2024
Gross margin
Gross margin for natural - gas assets (1)
$ 2,113,810 $ 2,073,533
Gross margin for crude - oil and NGLs assets (1)
407,211 395,886
Gross margin for produced - water assets (1)
435,501 341,784
Per - Mcf Gross margin for natural - gas assets (2)
1.07 1.08
Per - Bbl Gross margin for crude - oil and NGLs assets (2)
2.13 2.00
Per - Bbl Gross margin for produced - water assets (2)
0.74 0.81
Adjusted Gross Margin
Adjusted Gross Margin for natural - gas assets
$ 2,471,011 $ 2,411,438
Adjusted Gross Margin for crude - oil and NGLs assets
564,461 570,476
Adjusted Gross Margin for produced - water assets
514,085 394,879
Per - Mcf Adjusted Gross Margin for natural - gas assets (3)
1.30 1.30
Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (3)
3.01 2.94
Per - Bbl Adjusted Gross Margin for produced - water assets (3)
0.89 0.96
_________________________________________________________________________________________
(1) Excludes corporate-level depreciation and amortization.
(2) Average for period. Calculated as Gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.
(3) Average for period. Calculated as Adjusted Gross Margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.
63
Table of Contents
Year Ended December 31,
thousands 2025 2024
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss) $ 1,212,455 $ 1,611,252
Add:
Distributions from equity investments 122,364 142,236
Non-cash equity-based compensation expense (1)
50,803 37,994
Interest expense 390,490 378,513
Income tax expense 15,086 18,111
Depreciation and amortization 710,778 650,428
Long-lived asset and other impairments 14,760 6,206
Other expense 303 248
Less:
Gain (loss) on divestiture and other, net (11,113) 296,771
Gain (loss) on early extinguishment of debt — 5,403
Equity income, net – related parties 85,788 112,385
Other income 16,629 31,741
Items impacting comparability
Acquisition-related expenses (1)
(113,188) —
Adjusted EBITDA attributable to noncontrolling interests 58,141 54,650
Adjusted EBITDA (2)
$ 2,480,782 $ 2,344,038
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities $ 2,222,625 $ 2,136,860
Interest (income) expense, net 390,490 378,513
Accretion and amortization of long-term obligations, net (6,945) (9,238)
Current income tax expense (benefit) 11,142 3,900
Other (income) expense, net (16,629) (31,741)
Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850
Changes in assets and liabilities:
Accounts receivable, net (36,018) 42,798
Accounts and imbalance payables and accrued liabilities, net 3,969 21,935
Other items, net (174,290) (175,189)
Acquisition-related expenses (1)
113,188 —
Adjusted EBITDA attributable to noncontrolling interests (58,141) (54,650)
Adjusted EBITDA (2)
$ 2,480,782 $ 2,344,038
Cash flow information
Net cash provided by operating activities $ 2,222,625 $ 2,136,860
Net cash used in investing activities (1,085,206) (39,168)
Net cash used in financing activities (1,408,392) (1,280,015)
_________________________________________________________________________________________
(1) Acquisition-related expenses include (i) $97.3 million of severance costs and (ii) $15.9 million of third-party consulting and legal fees. Non-cash equity-based compensation expense for the year ended December 31, 2025, includes $7.3 million in acquisition-related severance costs.
(2) Includes non-cash revenue of $(14.0) million and $39.7 million for the years ended December 31, 2025 and 2024, respectively. See Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
64
Table of Contents
Year Ended December 31,
thousands 2025 2024
Reconciliation of Net cash provided by operating activities to Free Cash Flow
Net cash provided by operating activities $ 2,222,625 $ 2,136,860
Less:
Capital expenditures 727,991 833,856
Contributions to equity investments (including capitalized interest) — 9,690
Add:
Distributions from equity investments in excess of cumulative earnings — related parties 31,391 30,850
Free Cash Flow $ 1,526,025 $ 1,324,164
Cash flow information
Net cash provided by operating activities $ 2,222,625 $ 2,136,860
Net cash used in investing activities (1,085,206) (39,168)
Net cash used in financing activities (1,408,392) (1,280,015)
Gross margin. Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Revenue s, Cost of Product (Natural-gas purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
Gross margin increased by $143.1 million for the year ended December 31, 2025, primarily due to a $238.2 million increase in total revenues and other, partially offset by a $60.4 million increase in depreciation and amortization.
Net income (loss). Refer to Operating Results within this Item 7 for a discussion of the primary components of Net income (loss) as compared to the prior periods.
Net income (loss) decreased by $398.8 million for the year ended December 31, 2025, primarily due to (i) a $307.9 million decrease in gain (loss) on divestiture and other, net and (ii) a $273.0 million increase in total operating expenses. These amounts were offset partially by a $238.2 million increase in total revenues and other.
Net cash provided by operating activities. Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods.
65
Table of Contents
KEY PERFORMANCE METRICS
Year Ended December 31,
thousands except percentages and per-unit amounts 2025 2024 Inc/(Dec)
Adjusted Gross Margin
$ 3,549,557 $ 3,376,793 5 %
Per - Mcf Adjusted Gross Margin for natural - gas assets (1)
1.30 1.30 — %
Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (1)
3.01 2.94 2 %
Per - Bbl Adjusted Gross Margin for produced - water assets (1)
0.89 0.96 (7) %
Adjusted EBITDA 2,480,782 2,344,038 6 %
Free Cash Flow
1,526,025 1,324,164 15 %
_________________________________________________________________________________________
(1) Average for period. Calculated as Adjusted Gross Margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.
Adjusted Gross Margin. Adjusted Gross Margin increased by $172.8 million for the year ended December 31, 2025, primarily due to (i) the acquisition of Aris and increased throughput at the DBM water systems and (ii) increased throughput at the West Texas complex and DBM oil system. These increases were offset partially by (i) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024 and decreased throughput at the Springfield gas-gathering system, (ii) the sale of our interests in the Marcellus Interest systems, Saddlehorn, and Mont Belvieu JV during 2024, (iii) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput at the DJ Basin oil system, and (iv) decreased throughput at the Granger complex.
Per - Mcf Adjusted gross margin for natural - gas assets was unchanged for the year ended December 31, 2025, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, offset by lower average prices at the DJ Basin complex.
Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.07 for the year ended December 31, 2025, primarily due to (i) increased throughput at the DBM oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) lower throughput at TEP and FRP, which have lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (iii) the sale of our interest in Whitethorn LLC which had a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets. These increases were offset partially by decreased revenues associated with lower annual cumulative catch-up adjustments for cost-of-service changes at the DJ Basin oil and Springfield oil-gathering systems that increased revenues in the fourth quarter of 2024 and decreased revenues in the fourth quarter of 2025.
Per - Bbl Adjusted Gross Margin for produced - water assets decreased by $0.07 for the year ended December 31, 2025, primarily due to the acquisition of Aris.
Adjusted EBITDA. Adjusted EBITDA increased by $136.7 million for the year ended December 31, 2025, primarily due to a $238.2 million increase in total revenues and other. This amount was offset partially by (i) a $35.3 million increase in operation and maintenance expenses, (ii) a $34.7 million increase in cost of product (net of lower of cost or market inventory adjustments), (iii) a $19.9 million decrease in distributions from equity investments, and (iv) a $6.7 million increase in property taxes.
Free Cash Flow. Free Cash Flow increased by $201.9 million for the year ended December 31, 2025, primarily due to (i) a $105.9 million decrease in capital expenditures, (ii) an $85.8 million increase in net cash provided by operating activities, and (iii) a $9.7 million decrease in contributions to equity investments.
See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.
GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by the below - described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results.
66
Table of Contents
Impact of producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude - oil, natural - gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. The New York Mercantile Exchange West Texas Intermediate crude - oil daily settlement prices during 2024 ranged from a low of $65.75 per barrel in September 2024 to a high of $86.91 per barrel in April 2024, and prices during the year ended December 31, 2025, ranged from a low of $ 55.27 per barrel in December 2025 to a high o f $80.04 per barrel in January 2025. The Waha Hub natural-gas prices during 2024 ranged from a low of ($6.23) per MMBtu in August 2024 to a high of $8.27 per MMBtu in January 2024, and prices during the year ended December 31, 2025, ranged from a low of ($8.82) per MMBtu in October 2025 to a high of $ 7.50 per MMBtu in January 2025. The extent and duration of commodity - price volatility, and the associated direct and indirect impact on our business, cannot be predicted. To address the risks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.
Additionally, even in favorable commodity-price environments, our customers face operational challenges such as severe weather disruptions, oil and gas takeaway constraints, produced water recycling and disposal limitations, seismicity concerns, new regulatory requirements, and optimizing large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can significantly impact the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise.
Liquidity and access to capital markets. In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions. From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute.
Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are becoming more numerous, more stringent, and more complex. These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells. In addition, in certain areas in which we operate, public protests of oil and gas operations are not uncommon. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets. For examples of proposed regulations or other regulatory initiatives that could have a potentially material impact on us, see the Environmental Matters and Occupational Health and Safety Regulations section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K.
Impact of inflation and tariffs. High inflation in the U.S. has raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, raising operating costs and capital expenditures. Additionally, the Trump administration has imposed significant import tariffs, including on imports of steel and aluminum, and may impose further tariffs on other U.S. trading partners. These tariffs could substantially increase our operating and capital costs. While future inflation and tariff impacts are uncertain, higher operating and capital costs could materially and negatively affect financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.
67
Table of Contents
Impact of interest rates. Interest rates can be volatile, affecting our interest expense on RCF and commercial paper borrowings. Future increased interest rates would likely result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates may affect investor yield requirements. A rising interest-rate environment could have an adverse impact on our unit price and ability to issue equity to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our peers face similar interest-rate dynamics.
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash uses include equity and debt service, operating expenses, acquisitions, and capital expenditures. Our sources of liquidity, as of December 31, 2025, included cash and cash equivalents, cash flows generated from operations, effective borrowing capacity under the RCF, our commercial paper program, and potential issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short - term working-capital requirements and long - term capital - expenditure and debt-service requirements.
The amount of future distributions to unitholders will be determined by the Board on a quarterly basis. We distribute all our available cash, as defined in our partnership agreement, within 55 days following each quarter’s end. The Board declared a cash distribution to unitholders for the fourth quarter of 2025 of $0.910 per unit, or $379.7 million in the aggregate. The cash distribution was paid on February 13, 2026, to our unitholders of record at the close of business on February 2, 2026.
In February 2025, the Board authorized a buyback program of up to $250.0 million of our common units through December 31, 2026 (the “2025 Purchase Program”). The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to acquire any common units, and the program may be suspended or discontinued at our discretion without prior notice.
For the year ended December 31, 2026, capital expenditures are expected to range between $850.0 million to $1.0 billion (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).
Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or financing agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors, and the amounts involved may be material. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K.
Working capital . Working capital is an indication of liquidity and potential needs for short - term funding. Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and other capital activities. As of December 31, 2025, we had a $420.5 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. The effective borrowing capacity under the RCF was $2.0 billion as of December 31, 2025. Any outstanding commercial paper borrowings reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its commercial paper program. See Note 11—Selected Components of Working Capital and Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
68
Table of Contents
Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include (i) maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, or to remain in compliance with regulatory or legal requirements, and (ii) expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels. Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
Year Ended December 31,
thousands 2025 2024
Acquisitions $ 368,638 $ 443
Capital expenditures (1)
727,991 833,856
Capital incurred (1)
739,454 798,330
_________________________________________________________________________________________
(1) For the years ended December 31, 2025 and 2024, included $10.2 million and $15.2 million, respectively, of capitalized interest.
Acquisitions for the year ended December 31, 2025, included the acquisition of Aris. See Items Affecting the Comparability of Our Financial Results within this Item 7.
Capital expenditures decreased by $105.9 million for the year ended December 31, 2025, primarily due to decreases of (i) $216.8 million at the West Texas complex, primarily attributable to construction costs incurred in 2024 associated with the North Loving plant that was completed in the first quarter of 2025 and (ii) $23.3 million at the DBM water systems due to decreased construction of certain water - disposal wells, equipment, facilities, and well-connect projects. These decreases were offset partially by increases of (i) $63.5 million at the Powder River Basin complex primarily attributable to an increase in construction of facilities and well-connect projects and (ii) $25.5 million at the DBM oil system related to an increase in pipeline, oil pumping, and electrical distribution projects.
69
Table of Contents
Historical cash flow . The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities:
Year Ended December 31,
thousands 2025 2024
Net cash provided by (used in):
Operating activities $ 2,222,625 $ 2,136,860
Investing activities (1,085,206) (39,168)
Financing activities (1,408,392) (1,280,015)
Net increase (decrease) in cash and cash equivalents $ (270,973) $ 817,677
Operating activities . Net cash provided by operating activities increased for the year ended December 31, 2025, primarily due to the impact of changes in assets and liabilities, including cash received on certain contracts for which revenue recognition is deferred (See Note 2 — Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and higher cash operating income. These increases were offset partially by lower distributions from equity-investment earnings and higher interest expense. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.
Investing activities . Net cash used in investing activities for the year ended December 31, 2025, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, Powder River Basin complex, DJ Basin complex, DBM oil system, Chipeta complex, and DJ Basin oil system, (ii) cash paid, net of cash received for the acquisition of Aris, and (iii) distributions received from equity investments in excess of cumulative earnings.
Net cash used in investing activities for the year ended December 31, 2024, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, Powder River Basin complex, and DBM oil system, (ii) increases to materials and supplies inventory and other, (iii) proceeds related to the sale of several equity investments to third parties, (iv) proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party, and (v) distributions received from equity investments in excess of cumulative earnings.
Financing activities . Net cash used in financing activities for the year ended December 31, 2025, primarily included (i) distributions paid to WES unitholders and noncontrolling interest owners, (ii) repayment of the total principal amount outstanding of the 3.950% Senior Notes due 2025 and 3.100% Senior Notes due 2025 at par value, and (iii) proceeds from the 5.500% Senior Notes due 2035 and 4.800% Senior Notes due 2031 issued in December 2025.
Net cash used in financing activities for the year ended December 31, 2024, primarily included (i) distributions paid to WES unitholders and noncontrolling interest owners, (ii) net repayments under the commercial paper program, (iii) retiring portions of certain of WES Operating’s senior notes via open-market repurchases, and (iv) proceeds from the 5.450% Senior Notes due 2034 issued in August 2024.
70
Table of Contents
Debt and credit facilities. As of December 31, 2025, (i) the carrying value of outstanding debt was $8.6 billion, (ii) the estimated future interest and RCF fee payments total $459.8 million in 2026, (iii) the 4.650% Senior Notes due 2026 are classified as short-term debt on the consolidated balance sheet, and (iv) the effective borrowing capacity under WES Operating’s $2.0 billion RCF is $2.0 billion. Any outstanding commercial paper borrowings reduce the effective borrowing capacity under the RCF as WES Operating maintains availability under the RCF as support for its commercial paper program.
During the year ended December 31, 2025, WES Operating (i) completed the public offerings of $600.0 million in aggregate principal amount of 4.800% Senior Notes due 2031 and $600.0 million in aggregate principal amount of 5.500% Senior Notes due 2035, (ii) assumed $500.0 million in aggregate principal amount of 7.250% Senior Notes due 2030 in connection with the Aris acquisition (see Acquisitions and Divestitures within Items 1 and 2 of this Form 10-K ) , (iii) retired the 3.950% Senior Notes due 2025 on the maturity date of June 1, 2025, for $336.8 million, and (iv) retired the 3.100% Senior Notes due 2025 on the maturity date of February 3, 2025, for $663.8 million. WES Operating repaid the 3.950% Senior Notes due 2025 and 3.100% Senior Notes due 2025 with cash on hand, including proceeds received from the 2024 public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034.
For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Finance leases. We have finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming. As of December 31, 2025, we have future finance-lease payments of $8.8 million in 2026, and a total of $14.1 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in property, plant, and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2025, we expect to incur asset retirement costs of $9.9 million in 2026, and a total of $427.9 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Operating leases. We have operating leases for equipment supporting our operations, corporate offices, field offices, and easements, with both Occidental and third parties as lessors. As of December 31, 2025, we have future operating-lease payments of $66.4 million in 2026, and a total of $133.2 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Offload commitments. We have offload agreements with third parties providing natural-gas firm-processing capacity through 2028 and produced-water disposal capacity through 2036. As of December 31, 2025, we have future minimum payments under offload agreements totaling $19.6 million for 2026, and a total of $312.8 million in years thereafter.
Pipeline commitments. We have transportation contracts with volume commitments on multiple pipelines through 2038. As of December 31, 2025, we have estimated future minimum-volume-commitment fees totaling $4.8 million in 2026, and a total of $263.1 million in years thereafter.
71
Table of Contents
Credit risk . We bear credit risk through exposure to non - payment or non - performance by our counterparties (e.g., Occidental and other customers, financial institutions, and other parties), including risks from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our contractual rights to request adequate assurance of performance.
We expect our exposure to the concentrated risk of non - payment or non - performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental - produced volumes, but also, in some instances, the volumes of other working - interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements.
ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING
Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below.
Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands 2025 2024 2023
Net income (loss) attributable to WES $ 1,180,983 $ 1,573,571 $ 1,022,216
Limited partner interest in WES Operating not held by WES (1)
23,835 32,156 20,922
General and administrative expenses (2)
720 1,875 2,943
Other income (expense), net (359) (252) (275)
Income taxes 2,734 8 6
Net income (loss) attributable to WES Operating $ 1,207,913 $ 1,607,358 $ 1,045,812
_________________________________________________________________________________________
(1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.
(2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
72
Table of Contents
Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands 2025 2024 2023
WES net cash provided by operating activities $ 2,222,625 $ 2,136,860 $ 1,661,334
General and administrative expenses (1)
720 1,875 2,943
Non - cash equity - based compensation expense
(608) (581) (581)
Changes in working capital (29,656) (29,198) (15,226)
Other income (expense), net (359) (252) (275)
Income taxes — 8 6
WES Operating net cash provided by operating activities $ 2,192,722 $ 2,108,712 $ 1,648,201
WES net cash provided by (used in) financing activities $ (1,408,392) $ (1,280,015) $ (67,912)
Distributions to WES unitholders (2)
1,431,024 1,246,069 978,430
Distributions to WES from WES Operating (3)
(1,435,970) (1,246,702) (1,119,367)
Increase (decrease) in outstanding checks 2,411 50 (52)
Unit repurchases — — 134,602
Other 27,337 27,316 15,472
WES Operating net cash provided by (used in) financing activities $ (1,383,590) $ (1,253,282) $ (58,827)
_________________________________________________________________________________________
(1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
(2) Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(3) Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta.
WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders according to the terms of its limited partnership agreement. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
73
Table of Contents
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee. For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s historical carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.
Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in throughput forecasts or changes in future development plans by producers, to the extent they affect our operations, may trigger an impairment assessment.
Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. The primary assumptions used to estimate undiscounted future net cash flows include long-range customer throughput forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.
If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to impairment expense. Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.
Impairments of equity investments. Management assesses its equity investments for impairment when events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary. When evidence of an other-than-temporary loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense.
We recognized long-lived asset and other impairments of $14.8 million and $6.2 million for the years ended December 31, 2025 and 2024, respectively. See Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the periods presented.
74
Table of Contents
Fair value. Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Fair value estimates in business combination accounting. Business combination accounting requires that assets and liabilities be recorded at their estimated fair value in connection with the initial recognition of the transaction. Estimating the fair value of assets and liabilities in connection with business combination accounting requires management to make estimates, assumptions and judgments, and, in some cases, management may also utilize third-party specialists to assist and advise on those estimates.
In order to estimate the fair value of acquired assets and assumed liabilities, we utilize widely accepted valuation techniques that include market and discounted cash flow approaches. These approaches utilize assumptions that include, but are not limited to, estimated future cash flows, discount rates applied to estimated future cash flows, and estimated asset replacement costs. While we believe we have made reasonable assumptions to estimate the fair value, these assumptions are inherently uncertain.
The acquisition-date fair value recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
RECENT ACCOUNTING DEVELOPMENTS
See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
75
Table of Contents