Western Midstream Partners, LP 10-K

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 items and comparison of the year ended December 31, 2023, to the year ended December 31, 2022, 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, as filed with the SEC on February 21, 2024, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com. The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2024 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental. EXECUTIVE SUMMARY We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural - gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We own or have investments in assets located in Texas, New Mexico, and the Rocky Mountains (Colorado, Utah, and Wyoming). As of December 31, 2024, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems (1) 18 2 1 Treating facilities 42 3 — Natural - gas processing plants/trains 26 3 1 NGLs pipelines 3 — 4 Natural - gas pipelines 6 — 1 Crude - oil pipelines 2 1 1 _________________________________________________________________________________________ (1) Includes the DBM water systems. Significant financial and operational events during the year ended December 31, 2024, included the following: • 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. • 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. 54 Table of Contents • Our regular fourth - quarter 2024 per - unit distribution is unchanged from the third-quarter 2024 per-unit distribution of $0.875. • Natural - gas throughput attributable to WES totaled 5,052 MMcf/d for the year ended December 31, 2024, representing a 14% increase compared to year ended December 31, 2023. • Crude - oil and NGLs throughput attributable to WES totaled 530 MBbls/d for the year ended December 31, 2024, representing a 19% decrease compared to the year ended December 31, 2023. • 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) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,871 1,635 14 % DJ Basin 1,436 1,322 9 % Powder River Basin 456 120 NM Equity investments 517 466 11 % Other 946 1,050 (10) % Total throughput for natural - gas assets 5,226 4,593 14 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 243 214 14 % DJ Basin 92 71 30 % Powder River Basin 25 5 NM Equity investments 144 333 (57) % Other 37 42 (12) % Total throughput for crude - oil and NGLs assets 541 665 (19) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,147 1,029 11 % Total throughput for produced - water assets 1,147 1,029 11 % _________________________________________________________________________________________ NM — Not meaningful 55 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, and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems, and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather and dispose of produced water. We operate in Texas, New Mexico, Colorado, Utah, and Wyoming, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains. For example, for the year ended December 31, 2024, our West Texas and DJ Basin assets provided (i) 53% and 32%, respectively, of Total revenues and other, (ii) 40% and 31%, 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, 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. For the year ended December 31, 2024, 95% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) 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 the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors. 56 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 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 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. 57 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 2024 2023 Total revenues and other (1) $ 3,605,223 $ 3,106,476 Equity income, net – related parties 112,385 152,959 Total operating expenses (1) 2,043,647 1,869,770 Gain (loss) on divestiture and other, net 296,771 (10,102) Operating income (loss) 1,970,732 1,379,563 Interest expense (378,513) (348,228) Gain (loss) on early extinguishment of debt 5,403 15,378 Other income (expense), net 31,741 5,679 Income (loss) before income taxes 1,629,363 1,052,392 Income tax expense (benefit) 18,111 4,385 Net income (loss) 1,611,252 1,048,007 Net income (loss) attributable to noncontrolling interests 37,681 25,791 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,573,571 $ 1,022,216 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, and NGLs to related parties. Total operating expenses includes amounts charged by related parties for services received. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (2) For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7. For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2024” refer to the comparison of the year ended December 31, 2024, to the year ended December 31, 2023. Discussion of 2022 items and comparison of the year ended December 31, 2023, to the year ended December 31, 2022, 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, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com . 58 Table of Contents Throughput Year Ended December 31, 2024 2023 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 453 435 4 % Processing 4,256 3,692 15 % Equity investments (1) 517 466 11 % Total throughput 5,226 4,593 14 % Throughput attributable to noncontrolling interests (2) 174 161 8 % Total throughput attributable to WES for natural - gas assets 5,052 4,432 14 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 397 332 20 % Equity investments (1) 144 333 (57) % Total throughput 541 665 (19) % Throughput attributable to noncontrolling interests (2) 11 13 (15) % Total throughput attributable to WES for crude - oil and NGLs assets 530 652 (19) % Throughput for produced-water assets (MBbls/d) Gathering and disposal 1,147 1,029 11 % Throughput attributable to noncontrolling interests (2) 23 20 15 % Total throughput attributable to WES for produced - water assets 1,124 1,009 11 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting. (2) Includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests. Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 620 MMcf/d for the year ended December 31, 2024, 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 complexes due to increased production in the areas, (iii) higher volumes at the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (iv) higher volumes at the Springfield gas-gathering system due to new third-party production. 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 complex due to a contract expiration in the fourth quarter of 2023. Crude-oil and NGLs assets Total throughput attributable to WES for crude - oil and NGLs assets decreased by 122 MBbls/d for the year ended December 31, 2024, primarily due to (i) the divestiture of Whitethorn LLC, Mont Belvieu JV, Saddlehorn, and Panola in the first quarter of 2024. These decreases were offset partially by (i) higher volumes at the DBM and DJ Basin oil systems 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. Produced-water assets Total throughput attributable to WES for produced - water assets increased by 115 MBbls/d for the year ended December 31, 2024, due to higher production, partially offset by increased recycling activities in the upstream operations of our producers. 59 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Service revenues – fee based $ 3,248,262 $ 2,768,757 17 % Service revenues – product based 215,776 191,727 13 % Total service revenues $ 3,464,038 $ 2,960,484 17 % Service revenues – fee based Service revenues – fee based increased by $479.5 million for the year ended December 31, 2024, primarily due to increases of (i) $184.0 million at the West Texas complex due to increased throughput, a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums, (ii) $140.2 million at the Powder River Basin complex attributable to the acquisition of Meritage, (iii) $89.8 million at the DJ Basin complex primarily due to increased throughput and increased electricity-related rates billed to customers, partially offset by a decrease in deficiency fees, (iv) $87.5 million and $36.7 million at the DBM water and DBM oil systems, respectively, as a result of increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (v) $6.7 million at the Chipeta complex primarily due to new and amended contracts effective July 2024. These increases were offset partially by decreases of (i) $23.7 million at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024, (ii) $16.8 million and $4.3 million at the Springfield and DJ Basin oil systems, respectively, primarily due to decreased revenues associated with demand volumes and lower cumulative catch-up adjustments for changes in estimated consideration in 2024 compared to 2023, partially offset by increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, (iii) $11.8 million at the Granger complex due to a contract expiration in the fourth quarter of 2023, and (iv) $10.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, partially offset by increased throughput. Service revenues – product based Service revenues – product based increased by $24.0 million for the year ended December 31, 2024, primarily due to increases of (i) $15.4 million at the West Texas complex due to increased volumes sold, (ii) $5.3 million at the DJ Basin complex due to a contract change effective during the second quarter of 2024, partially offset by decreased average prices, (iii) $4.7 million at the Powder River Basin complex attributable to the acquisition of Meritage, 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 $3.4 million at the Chipeta complex due to decreased volumes sold. 60 Table of Contents 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 2023 Inc/ (Dec) Equity income, net – related parties $ 112,385 $ 152,959 (27) % Equity income, net – related parties decreased by $40.6 million for the year ended December 31, 2024, primarily due to decreases of (i) $37.6 million resulting from the sale of several equity investments to third parties in the first quarter of 2024 and (ii) $8.0 million at TEP. These decreases were offset partially by an increase of $4.6 million at Red Bluff. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 61 Table of Contents Cost of Product and Operation and Maintenance Expenses Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Natural-gas purchases $ 10,586 $ 32,515 (67) % NGLs purchases 252,591 211,468 19 % Other (90,926) (79,385) (15) % Cost of product 172,251 164,598 5 % Operation and maintenance 880,568 762,530 15 % Total Cost of product and Operation and maintenance expenses $ 1,052,819 $ 927,128 14 % Natural-gas purchases Natural-gas purchases decreased by $21.9 million for the year ended December 31, 2024, primarily due to decreases of (i) $15.3 million at the West Texas complex due to lower average prices and (ii) $6.2 million at the Granger complex attributable to a contract change effective during 2023 and decreased volumes purchased. NGLs purchases NGLs purchases increased by $41.1 million for the year ended December 31, 2024, primarily due to increases of (i) $39.4 million at the West Texas complex primarily attributable to increased volumes purchased and average prices and (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 a decrease of $5.6 million at the Chipeta complex due to a contract change effective during the third quarter of 2024. Other items Other items decreased by $11.5 million for the year ended December 31, 2024, primarily due to decreases of $32.5 million 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) $13.6 million at the DJ Basin complex primarily attributable to changes in imbalance positions. Operation and maintenance expense Including the impact of operating the assets acquired with Meritage, operation and maintenance expense increased by $118.0 million for the year ended December 31, 2024, primarily due to increases of (i) $38.5 million in salaries and wages costs, (ii) $25.1 million in equipment, materials, maintenance, and repair costs, (iii) $16.7 million in chemical and treating services, (iv) $10.2 million in land-related costs, (v) $9.0 million in equipment rental costs, (vi) $7.1 million in water-disposal costs, and (vii) $5.4 million in utility expense. 62 Table of Contents Other Operating Expenses Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) General and administrative $ 271,526 $ 232,632 17 % Property and other taxes 62,668 56,458 11 % Depreciation and amortization 650,428 600,668 8 % Long - lived asset and other impairments 6,206 52,884 (88) % Total other operating expenses $ 990,828 $ 942,642 5 % General and administrative expenses General and administrative expenses increased by $38.9 million for the year ended December 31, 2024, primarily due to increases of (i) $27.5 million in personnel costs, (ii) $10.5 million in information technology costs, and (iii) $7.0 million in other corporate-related expenses. These increases were offset partially by a decrease of $6.1 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 $49.8 million for the year ended December 31, 2024, primarily due to increases of (i) $44.7 million at the Powder River Basin complex primarily attributable to the acquisition of Meritage and (ii) $22.5 million and $7.2 million at 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 DJ Basin complex primarily due to acceleration of depreciation expense during 2023 and updated salvage values, (ii) $6.4 million due to the sale of the Marcellus Interest systems in the second quarter of 2024, and (iii) $4.3 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 for the year ended December 31, 2024, was primarily due to a $4.2 million impairment of certain corporate office leases that are no longer being utilized. 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. 63 Table of Contents Interest Expense Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Long - term and short - term debt $ (377,850) $ (348,393) 8 % Finance lease liabilities (2,573) (1,083) 138 % Commitment fees and amortization of debt-related costs (13,305) (12,395) 7 % Capitalized interest 15,215 13,643 12 % Interest expense $ (378,513) $ (348,228) 9 % Interest expense increased by $30.3 million for the year ended December 31, 2024, primarily due to increases of (i) $29.3 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, (ii) $16.1 million of interest incurred on the 5.450% Senior Notes due 2034 that were issued during the third quarter of 2024, (iii) $12.1 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, and (iv) $2.7 million due to borrowings in 2024 on the commercial paper program that was established during the fourth quarter of 2023. These increases were offset partially by decreases of (i) $14.8 million primarily due to no outstanding borrowings under the RCF during 2024 and (ii) $14.6 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. Other Income (Expense), Net Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Other income (expense), net $ 31,741 $ 5,679 NM Other income (expense), net increased by $26.1 million for the year ended December 31, 2024, primarily due to interest income earned resulting from higher cash and cash equivalent balances throughout 2024. Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Income (loss) before income taxes $ 1,629,363 $ 1,052,392 55 % Income tax expense (benefit) 18,111 4,385 NM Effective tax rate 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 the year ended December 31, 2024, the variance from the federal statutory rate was primarily impacted by a state margin tax rate increase associated with no longer being included in Occidental’s affiliated group tax return beginning in September 2024 due to Occidental’s sale of 19.5 million WES common units in August 2024 and the resulting decrease in WES ownership, inclusive of its ownership in WES Operating. 64 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) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following: • our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis; • the ability of our assets to generate cash flow to make distributions; and • the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. Free Cash Flow. We define “Free Cash Flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free Cash Flow an appropriate metric for assessing capital discipline, cost efficiency, and balance - sheet strength. Although Free Cash Flow is the metric used to assess 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. 65 Table of Contents Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted Gross Margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA. The GAAP measure that is most directly comparable to Free Cash Flow is net cash provided by operating activities. Our non - GAAP financial measures of Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures. Management compensates for the limitations of Adjusted Gross Margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results. The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted Gross Margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free Cash Flow: Year Ended December 31, 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. 66 Table of Contents 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 2023 Gross margin Gross margin for natural - gas assets (1) $ 2,073,533 $ 1,738,125 Gross margin for crude - oil and NGLs assets (1) 395,886 368,444 Gross margin for produced - water assets (1) 341,784 259,541 Per - Mcf Gross margin for natural - gas assets (2) 1.08 1.04 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 2.00 1.52 Per - Bbl Gross margin for produced - water assets (2) 0.81 0.69 Adjusted Gross Margin Adjusted Gross Margin for natural - gas assets $ 2,411,438 $ 2,067,528 Adjusted Gross Margin for crude - oil and NGLs assets 570,476 589,091 Adjusted Gross Margin for produced - water assets 394,879 307,228 Per - Mcf Adjusted Gross Margin for natural - gas assets (3) 1.30 1.28 Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (3) 2.94 2.48 Per - Bbl Adjusted Gross Margin for produced - water assets (3) 0.96 0.83 _________________________________________________________________________________________ (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. 67 Table of Contents Year Ended December 31, thousands 2024 2023 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,611,252 $ 1,048,007 Add: Distributions from equity investments 142,236 194,273 Non - cash equity - based compensation expense 37,994 32,005 Interest expense 378,513 348,228 Income tax expense 18,111 4,385 Depreciation and amortization 650,428 600,668 Impairments 6,206 52,884 Other expense 248 1,739 Less: Gain (loss) on divestiture and other, net 296,771 (10,102) Gain (loss) on early extinguishment of debt 5,403 15,378 Equity income, net – related parties 112,385 152,959 Other income 31,741 6,976 Adjusted EBITDA attributable to noncontrolling interests (1) 54,650 48,345 Adjusted EBITDA $ 2,344,038 $ 2,068,633 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Interest (income) expense, net 378,513 348,228 Accretion and amortization of long - term obligations, net (9,238) (8,151) Current income tax expense (benefit) 3,900 3,341 Other (income) expense, net (31,741) (5,679) Distributions from equity investments in excess of cumulative earnings – related parties 30,850 39,104 Changes in assets and liabilities: Accounts receivable, net 42,798 78,346 Accounts and imbalance payables and accrued liabilities, net 21,935 68,019 Other items, net (175,189) (67,564) Adjusted EBITDA attributable to noncontrolling interests (1) (54,650) (48,345) Adjusted EBITDA $ 2,344,038 $ 2,068,633 Cash flow information Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Net cash provided by (used in) investing activities (39,168) (1,607,291) Net cash provided by (used in) financing activities (1,280,015) (67,912) _________________________________________________________________________________________ (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. 68 Table of Contents Year Ended December 31, thousands 2024 2023 Reconciliation of Net cash provided by operating activities to Free Cash Flow Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Less: Capital expenditures 833,856 735,080 Contributions to equity investments – related parties 9,690 1,153 Add: Distributions from equity investments in excess of cumulative earnings – related parties 30,850 39,104 Free Cash Flow $ 1,324,164 $ 964,205 Cash flow information Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Net cash provided by (used in) investing activities (39,168) (1,607,291) Net cash provided by (used in) financing activities (1,280,015) (67,912) 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 Revenue s, 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 $441.3 million for the year ended December 31, 2024, primarily due to a $498.7 million increase in total revenues and other. This increase was offset partially by (i) a $49.8 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 by $563.2 million for the year ended December 31, 2024, primarily due to (i) a $498.7 million increase in total revenues and other and (ii) a $306.9 million increase in gain (loss) on divestiture and other, net. These amounts were offset partially by (i) a $173.9 million increase in total operating expenses, (ii) a $40.6 million decrease in equity income, net – related parties, and (iii) a $30.3 million increase in interest expense. 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. 69 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2024 2023 Inc/ (Dec) Adjusted Gross Margin $ 3,376,793 $ 2,963,847 14 % Per - Mcf Adjusted Gross Margin for natural - gas assets (1) 1.30 1.28 2 % Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (1) 2.94 2.48 19 % Per - Bbl Adjusted Gross Margin for produced - water assets (1) 0.96 0.83 16 % Adjusted EBITDA 2,344,038 2,068,633 13 % Free cash flow 1,324,164 964,205 37 % _________________________________________________________________________________________ (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 $412.9 million for the year ended December 31, 2024, primarily due to (i) increased throughput and a higher average fee resulting from cost-of-service rate redeterminations effective January 1, 2024, at the West Texas complex, DBM water systems, and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput at the DJ Basin complex. These increases were offset partially by (i) the sale of our interests in the Marcellus Interest systems, Mont Belvieu JV, and Saddlehorn during 2024, (ii) decreased distributions from TEP, (iii) decreased revenues associated with demand volumes and a lower cumulative catch-up adjustment for changes in estimated consideration in 2024 compared to 2023 at the Springfield system, partially offset by increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (iv) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, partially offset by increased throughput. Per - Mcf Adjusted Gross Margin for natural - gas assets increased by $0.02 for the year ended December 31, 2024, 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, in addition to a higher average fee 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 Margin for crude - oil and NGLs assets increased by $0.46 for the year ended December 31, 2024, primarily due to (i) the sale of our interests in Whitethorn LLC, Mont Belvieu JV, and Saddlehorn in the first quarter of 2024, all of which had lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (ii) increased throughput at the DBM oil system, which has a higher-than-average per-Mcf margin as compared to our other crude-oil and NGLs assets, in addition to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024. These increases were offset partially by (i) decreased revenues associated with demand volumes and lower cumulative catch-up adjustments for changes in estimated consideration in 2024 compared to 2023 at the DJ Basin oil and Springfield systems, partially offset by higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (ii) decreased distributions at TEP. Per - Bbl Adjusted Gross Margin for produced - water assets increased by $0.13 for the year ended December 31, 2024, primarily due to higher throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024. Adjusted EBITDA. Adjusted EBITDA increased by $275.4 million for the year ended December 31, 2024, primarily due to a $498.7 million increase in total revenues and other. This was offset partially by (i) a $118.0 million increase in operation and maintenance expenses, (ii) a $52.0 million decrease in distributions from equity investments, (iii) a $32.9 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, (iv) a $7.8 million increase in cost of product (net of lower of cost or market inventory adjustments), and (v) a $6.2 million increase in property and other taxes. 70 Table of Contents 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. 71 Table of Contents 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 somewhat abated during 2024, 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 has increased our operating costs and capital expenditures. Additionally, the Trump administration has recently implemented a 10% tariff on Chinese imports and announced a 25% tariff on imports of steel and aluminum. Plans by the Trump administration to impose additional import tariffs on Canada 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 we cannot predict any future inflation trends or the impact of current or future import tariffs, higher operating and capital costs could materially and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees. Impact of interest rates. Short- and long-term interest rates can be volatile, resulting in immediate changes to interest expense on RCF borrowings 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. 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. 72 Table of Contents 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, 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 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 of $0.875 per unit, or $341.0 million in the aggregate. The cash distribution was paid on February 14, 2025, to our unitholders of record at the close of business on February 3, 2025. 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, capital expenditures are expected to range between $625.0 million to $775.0 million (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. 73 Table of Contents 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, 2024, we had a $155.5 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. 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. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels. Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2024 2023 Acquisitions $ 443 $ 877,746 Capital expenditures (1) 833,856 735,080 Capital incurred (1) 798,330 752,338 _________________________________________________________________________________________ (1) The years ended December 31, 2024 and 2023, included $15.2 million and $13.6 million, respectively, of capitalized interest. Acquisitions for the year ended December 31, 2023, included the acquisition of Meritage. See Items Affecting the Comparability of Our Financial Results within this Item 7. Capital expenditures increased by $98.8 million for the year ended December 31, 2024, primarily due to increases of (i) $88.3 million at the West Texas complex, primarily attributable to engineering, equipment, and construction milestone payments for the North Loving Plant, (ii) $28.2 million at the Powder River Basin complex primarily attributable to the acquisition of Meritage, (iii) $24.2 million at the DBM water systems due to increased construction of certain water - disposal wells, equipment, facilities, and well-connect projects, and (iv) $8.2 million at the Chipeta complex primarily related to expansion projects. These increases were offset partially by a decrease of $58.3 million at the DBM oil system related to a decrease in pipeline, oil treating, and oil pumping projects. 74 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 2024 2023 Net cash provided by (used in): Operating activities $ 2,136,860 $ 1,661,334 Investing activities (39,168) (1,607,291) Financing activities (1,280,015) (67,912) Net increase (decrease) in cash and cash equivalents $ 817,677 $ (13,869) Operating activities . Net cash provided by operating activities increased for the year ended December 31, 2024, 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). 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, primarily included the following: • $833.9 million of 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; • $18.3 million of increases to materials and supplies inventory and other; • $582.7 million of proceeds related to the sale of several equity investments to third parties; • $206.2 million of proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party; and • $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 75 Table of Contents • $790.3 million of net proceeds from the 5.450% Senior Notes due 2034 issued in August 2024, which will be used to repay a portion of the maturing 3.100% Senior Notes due 2025 and 3.950% Senior Notes due 2025 and for general partnership purposes, including the funding of capital expenditures. Net cash used in financing activities for the year ended December 31, 2023, primarily included the following: • $1,495.0 million of repayments of outstanding borrowings under the RCF; • $1,008.9 million of distributions paid to WES unitholders and noncontrolling interest owners; • $259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; • $213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value; • $134.6 million of unit repurchases; • $1,120.0 million of borrowings under the RCF, which were used for general partnership purposes; • $740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes; • $609.9 million of net borrowings under the commercial paper program, which were used for general partnership purposes; and • $592.8 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes. 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. 76 Table of Contents Finance lease liabilities. We have finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming. As of December 31, 2024, we have future finance-lease payments of $11.5 million in 2025 and a total of $27.4 million in years thereafter. Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in property, plant, and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 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. 77 Table of Contents 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 2023 2022 Net income (loss) attributable to WES $ 1,573,571 $ 1,022,216 $ 1,217,103 Limited partner interest in WES Operating not held by WES (1) 32,156 20,922 24,899 General and administrative expenses (2) 1,875 2,943 2,656 Other income (expense), net (252) (275) (45) Income taxes 8 6 7 Net income (loss) attributable to WES Operating $ 1,607,358 $ 1,045,812 $ 1,244,620 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2024 2023 2022 WES net cash provided by operating activities $ 2,136,860 $ 1,661,334 $ 1,701,426 General and administrative expenses (1) 1,875 2,943 2,656 Non - cash equity - based compensation expense (581) (581) (570) Changes in working capital (29,198) (15,226) (9,341) Other income (expense), net (252) (275) (45) Income taxes 8 6 7 WES Operating net cash provided by operating activities $ 2,108,712 $ 1,648,201 $ 1,694,133 WES net cash provided by (used in) financing activities $ (1,280,015) $ (67,912) $ (1,398,532) Distributions to WES unitholders (2) 1,246,069 978,430 735,755 Distributions to WES from WES Operating (3) (1,246,702) (1,119,367) (1,219,635) Increase (decrease) in outstanding checks 50 (52) 103 Unit repurchases — 134,602 487,590 Other 27,316 15,472 9,326 WES Operating net cash provided by (used in) financing activities $ (1,253,282) $ (58,827) $ (1,385,393) _________________________________________________________________________________________ (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. 78 Table of Contents 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. 79 Table of Contents 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. RECENT ACCOUNTING DEVELOPMENTS See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 80 Table of Contents