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Item 7. Management’s Discussion and Analysis

2025-02-26 compared with 2024-02-21 · 143 added, 158 removed, 560 unchanged (35% of the section changed)

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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 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, 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, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.

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).

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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, the Rocky Mountains (Colorado, Utah, and Wyoming), and North - central Pennsylvania.

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:

Operated Operated

Interests Non-Operated

Interests Equity

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Significant financial and operational events during the year ended December 31, 2024, included the following:

• On October 13, 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments).

See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information.

• WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029.

Net proceeds from the offering 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.

See Liquidity and Capital Resources within this Item 7 for additional information.

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

See Acquisitions and Divestitures within this Item 7 for additional information.

• WES Operating completed the public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034.

Net proceeds from this offering were used to repay borrowings under the RCF and for general partnership purposes.

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 redeemed the $213.1 million total principal amount outstanding of the Floating-Rate Senior Notes due 2023 at par value with cash on hand.

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

• In November 2023, WES operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion.

See Liquidity and Capital Resources within this Item 7 for additional information.

• Our fourth - quarter 2023 per - unit distribution is unchanged from the third-quarter 2023 per-unit distribution of $0.575.

• The Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance.

This Enhanced Distribution was paid, along with our regular first-quarter 2023 distribution, on May 15, 2023, to our unitholders of record at the close of business on May 1, 2023.

• We repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million.

• Natural - gas throughput attributable to WES totaled 4,432 MMcf/d for the year ended December 31, 2023, representing a 5% increase compared to the year ended December 31, 2022.

• 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 1,009 MBbls/d for the year ended December 31, 2023, representing a 21% increase compared to the year ended December 31, 2022.

• Gross margin was $2,341.2 million for the year ended December 31, 2023, representing a 4% increase compared to the year ended December 31, 2022.

• 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 $1.28 per Mcf for the year ended December 31, 2023, representing a 3% decrease compared to the year ended December 31, 2022.

• 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 $0.83 per Bbl for the year ended December 31, 2023, representing a 12% decrease compared to the year ended December 31, 2022.

• 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:

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DJ Basin 92 71 30 %

Powder River Basin 5 — 100 %

Powder River Basin 25 5 NM

Equity investments 144 333 (57) %

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We also gather and dispose of produced water.

We operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains.

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.

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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) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under certain of our processing agreements.

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.

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HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance.

These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures:

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).

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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 and to the annual budget.

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 is closely monitored.

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 historic results of operations or cash flows for the reasons described below.

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, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement.

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.

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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.

In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing.

Total proceeds were received during the fourth quarter of 2022, resulting in a net gain on sale of $109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million.

Subsequent to the acquisition, (i) we are the sole owner and operator of the asset, (ii) Ranch Westex is no longer accounted for under the equity method of accounting, and (iii) the Ranch Westex gas processing plant is included as part of the operations of the West Texas complex.

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

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 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, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

RESULTS OF OPERATIONS

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Equity investments (1)

466 483 (4) %

Total throughput 5,226 4,593 14 %

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Natural-gas assets

Total throughput attributable to WES for natural - gas assets increased by 222 MMcf/d for the year ended December 31, 2023, primarily due to (i) higher volumes at the West Texas complex due to increased production in the area, (ii) higher volumes at the Powder River Basin complex as a result of the Meritage acquisition, (iii) higher volumes at the Springfield gas-gathering system due to new third-party production, (iv) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (v) higher volumes at the MIGC system.

These increases were offset partially by (i) lower volumes at the Granger complex and Marcellus Interest systems due to production declines in the surrounding areas, (ii) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition, and (iii) lower volumes at the Mi Vida plant.

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 24 MBbls/d for the year ended December 31, 2023, primarily due to (i) lower volumes on the Cactus II pipeline, which was sold in the fourth quarter of 2022, and (ii) lower volumes at the DJ Basin oil system resulting from production declines in the area.

These decreases were offset partially by (i) increased volumes on the Whitethorn and Saddlehorn pipelines, (ii) higher volumes at the DBM oil system resulting from increased production in the area, and (iii) higher volumes on the Thunder Creek NGL pipeline which was acquired as part of the Meritage acquisition.

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 173 MBbls/d for the year ended December 31, 2023, due to higher production and new third-party connections brought online during 2023.

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.

Service Revenues

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Service revenues – fee based

Service revenues – fee based increased by $166.7 million for the year ended December 31, 2023, primarily due to increases of (i) $114.1 million at the West Texas complex as a result of increased throughput and electricity-related rates billed to customers, (ii) $42.6 million at the Powder River Basin complex as a result of increased throughput attributable to the acquisition of Meritage (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7), (iii) $22.7 million at the DJ Basin complex due to increased deficiency fees on demand volumes and electricity-related rates billed to customers, (iv) $20.8 million and $12.1 million at the DBM water and DBM oil systems, respectively, due to increased throughput, partially offset by decreased deficiency fees, and (v) $5.6 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 compared to 2022, partially offset by decreased throughput and deficiency fees.

These increases were partially offset by decreases of (i) $17.5 million at the Springfield system primarily due to decreased demand-fee revenue and a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by increased throughput, (ii) $12.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, and (iii) $12.1 million at the Chipeta complex due to decreased deficiency fees.

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 decreased by $58.0 million for the year ended December 31, 2023, primarily due to decreases of (i) $22.0 million at the West Texas complex due to decreased average prices and lower product-related electricity reimbursements from customers, (ii) $14.5 million and $6.1 million at the DJ Basin and Powder River Basin complexes, respectively, due to decreased average prices, and (iii) $9.2 million and $4.3 million at the Red Desert and Granger complexes, respectively, due to decreased average prices and volumes sold.

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.

Product Sales

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Natural-gas sales

Natural - gas sales decreased by $88.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $72.8 million at the West Texas complex due to decreased average prices, partially offset by higher volumes sold and (ii) $17.8 million at the Red Desert complex due to decreased average prices.

These decreases were partially offset by an increase of $7.7 million at the DJ Basin complex as a result of contract mix, partially offset by decreased volumes sold and average prices.

NGLs sales decreased by $165.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $94.7 million at the West Texas complex due to changes in contract mix and decreased average prices, (ii) $22.9 million, $10.0 million, and $3.6 million at the Chipeta, Granger, and Red Desert complexes, respectively, due to decreased average prices and volumes sold, (iii) $22.9 million at the DJ Basin complex due to decreased average prices, partially offset by increased volumes sold, and (iv) $7.5 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

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 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

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Equity income, net – related parties $ 112,385 $ 152,959 (27) %

Equity income, net – related parties decreased by $30.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.7 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7) and (ii) $9.1 million, $6.0 million, and $3.5 million at TEP, Mont Belvieu JV, and Whitethorn, respectively.

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.

Cost of Product and Operation and Maintenance Expenses

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thousands except percentages 2024 2023 Inc/

Residue purchases $ 32,515 $ 173,104 (81) %

Natural-gas purchases

$ 10,586 $ 32,515 (67) %

NGLs purchases 252,591 211,468 19 %

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Total Cost of product and Operation and maintenance expenses $ 1,052,819 $ 927,128 14 %

Residue purchases

Residue purchases decreased by $140.6 million for the year ended December 31, 2023, primarily due to decreases of (i) $84.1 million at the West Texas complex attributable to changes in contract mix during 2022 and lower average prices, (ii) $19.3 million at the Chipeta complex due to decreased volumes purchased and lower average prices, and (iii) $15.7 million and $8.2 million at the Red Desert and DJ Basin complexes, respectively, primarily due to lower average prices.

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 decreased by $109.3 million for the year ended December 31, 2023, primarily due to decreases of (i) $61.5 million and $30.7 million at the West Texas and DJ Basin complexes, respectively, attributable to lower average prices and (ii) $7.7 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

Other items decreased by $6.4 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.5 million at the West Texas complex due to changes in imbalance positions, partially offset by higher offload costs, and (ii) $3.8 million and $2.9 million at the Red Desert complex and MIGC system, respectively, attributable to changes in imbalance positions.

These decreases were partially offset by an increase of $16.9 million at the DJ Basin complex due to changes in imbalance positions.

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 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

Operation and maintenance expense increased by $108.0 million for the year ended December 31, 2023, primarily due to increases of (i) $35.8 million for equipment maintenance and repair expense, (ii) $27.7 million for salaries and wages costs, (iii) $11.8 million in utility expense, (iv) $9.6 million in land-related costs, (v) $8.9 million in higher equipment rental costs, (vi) $8.0 million in water-disposal costs, and (vii) $5.6 million attributable to higher contract labor and consulting 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.

Other Operating Expenses

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General and administrative expenses

General and administrative expenses increased by $38.6 million for the year ended December 31, 2023, primarily due to increases of (i) $16.2 million in personnel costs, including costs related to the acquisition of Meritage, (ii) $9.8 million in information technology costs, and (iii) $7.0 million in consulting and legal costs.

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 decreased by $22.1 million for the year ended December 31, 2023, primarily due to decreases in the ad valorem property tax accrual during 2023 related to the finalization of 2022 assessments at the DJ Basin complex.

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 $18.3 million for the year ended December 31, 2023, primarily due to increases of (i) $10.1 million and $7.3 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service, (ii) $9.9 million at the Powder River Basin complex associated with the acquisition of Meritage, and (iii) $7.2 million related to depreciation for capitalized information technology implementation costs.

These increases were offset partially by a decrease of $13.0 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2022.

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.

Long - lived asset and other impairment expense for the year ended December 31, 2022, was primarily due to a $19.9 million other-than-temporary impairment of our investment in White Cliffs.

For further information on Long - lived asset and other impairment expense, 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 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.

Interest Expense

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Interest expense $ (378,513) $ (348,228) 9 %

Interest expense increased by $14.3 million for the year ended December 31, 2023, primarily due to increases of (i) $34.7 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, (ii) $10.0 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, and (iii) $3.0 million primarily due to borrowings on the commercial paper program that was established during the fourth quarter of 2023.

These increases were offset partially by decreases of (i) $14.6 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, (ii) $8.0 million due to higher capitalized interest, (iii) $6.7 million due to the redemption of the total principal amount outstanding of the Floating-Rate Senior Notes due 2023 during the first quarter of 2023, and (iv) $5.1 million due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 during the second quarter of 2022.

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.

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Other income (expense), net $ 31,741 $ 5,679 NM

Other income (expense), net increased by $4.1 million for the year ended December 31, 2023, primarily due to interest income earned resulting from higher interest rates and cash and cash equivalent balances throughout 2023, partially offset by interest recorded in 2023 related to a sales tax audit.

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/

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.

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However, income apportionable to Texas is subject to Texas margin tax.

See Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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.

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

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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 WES’s 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 should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes.

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.

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$ 3,376,793 $ 2,963,847

_________________________________________________________________________________________

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

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Net cash provided by operating activities $ 2,136,860 $ 1,661,334

Net cash used in investing activities (1,607,291) (218,237)

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)

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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 used in investing activities (1,607,291) (218,237)

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 (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).

Gross margin increased by $92.8 million for the year ended December 31, 2023, due to a $256.3 million decrease in cost of product.

This amount was offset partially by (i) a $145.2 million decrease in total revenues and other and (ii) an $18.3 million increase in depreciation and amortization.

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) decreased by $203.4 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $113.8 million decrease in gain (loss) on divestiture and other, net, (iii) a $30.5 million decrease in equity income, net – related parties, and (iv) a $14.3 million increase in interest expense.

These amounts were offset partially by (i) an $81.2 million decrease in total operating expenses and (ii) a $15.3 million increase in gain (loss) on early extinguishment of debt.

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.

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Adjusted Gross Margin

$ 3,376,793 $ 2,963,847 14 %

Per - Mcf Adjusted Gross Margin for natural - gas assets (1)

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Adjusted Gross Margin.

Adjusted gross margin increased by $38.4 million for the year ended December 31, 2023, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput, partially offset by decreased deficiency fees at the DBM water systems.

These increases were partially offset by (i) a decrease in distributions from Cactus II, which was sold in the fourth quarter of 2022, (ii) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue, partially offset by increased throughput at the Springfield system, (iii) decreased deficiency fees at the Chipeta complex, (iv) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, (v) a decrease in distributions from Ranch Westex, which was acquired in the third quarter of 2022 and is included in the West Texas complex subsequent to the acquisition, and (vi) decreased throughput at the Granger complex.

Per - Mcf Adjusted gross margin for natural - gas assets decreased by $0.04 for the year ended December 31, 2023, primarily due to (i) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue at the Springfield system, and (ii) decreased deficiency fees at the Chipeta complex.

These decreases were partially offset by (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, and (ii) increased deficiency fees at the DJ Basin complex.

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.02 for the year ended December 31, 2023, primarily due to (i) decreases in throughput and distributions from Cactus II, which was sold in the fourth quarter of 2022 and had lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by decreased throughput and deficiency fees at the DJ Basin oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (iii) an increase in distributions from FRP.

These increases were partially offset by decreases in distributions from Whitethorn LLC, Mont Belvieu JV, and Saddlehorn.

Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.11 for the year ended December 31, 2023, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2023, and lower deficiency fee revenues.

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 decreased by $59.3 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $108.0 million increase in operation and maintenance expenses, (iii) a $55.8 million decrease in distributions from equity investments, and (iv) a $34.4 million increase in general and administrative expenses excluding non - cash equity - based compensation expense.

These amounts were offset partially by (i) a $256.2 million decrease in cost of product (net of lower of cost or market inventory adjustments), and (ii) a $22.1 million decrease in property and other taxes.

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.

Free Cash Flow.

Free cash flow decreased by $304.3 million for the year ended December 31, 2023, primarily due to (i) a $247.9 million increase in capital expenditures, (ii) a $40.1 million decrease in net cash provided by operating activities, and (iii) a $24.8 million decrease in distributions from equity investments in excess of cumulative earnings.

These amounts were offset partially by an $8.5 million decrease in contributions to equity investments.

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.

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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.

During 2020, oil and natural - gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19.

In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine.

For example, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude - oil daily settlement prices during 2022 ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022, and prices during the year ended December 31, 2023, ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023.

Similar disruptions could occur as a consequence of the current conflict in the Middle East.

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, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs.

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.

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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.

Impact of inflation and supply-chain disruptions.

economy has recently experienced significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine.

More specifically, the continued bottlenecks and disruptions have caused difficulties within the U.S.

and global supply chains, creating logistical delays along with labor shortages.

Continued 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.

Increases in inflationary pressure could materially and negatively impact our financial results.

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, commercial paper borrowings, and other floating-rate debt securities.

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.

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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 competitors face similar interest-rate dynamics.

However, we expect our cost of capital to remain competitive, as our peers face similar interest-rate dynamics.

Acquisition opportunities.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include equity and debt service, operating expenses, and capital expenditures.

Our sources of liquidity, as of December 31, 2023, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, our commercial paper program, and potential issuances of additional equity or debt securities.

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.

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The cash distribution was paid on February 14, 2025, to our unitholders of record at the close of business on February 3, 2025.

To facilitate the distribution of available cash, during 2022 we adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the regular first-quarter distribution of the following year (beginning in 2023), in a target amount equal to Free cash flow generated in the prior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases.

This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of our business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing-twelve-months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect.

Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7.

In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance, which was paid in conjunction with our regular first-quarter 2023 distribution on May 15, 2023.

In 2022, we announced a common-unit buyback program of up to $1.25 billion through December 31, 2024.

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 purchase any specific dollar amount or number of units and may be suspended or discontinued at any time.

During the year ended December 31, 2023, we repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million.

The units were canceled immediately upon receipt.

As of December 31, 2023, we had an authorized amount of $627.8 million remaining under the program.

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).

Total-year capital expenditures guidance includes capital expenditures attributable to (i) a portion of Mentone Train III, which is expected to be complete and in-service at the end of the first quarter of 2024, (ii) a portion of the North Loving plant, a new 250 MMcf/d cryogenic processing plant in the North Loving area of our West Texas complex that was sanctioned in May 2023, and (iii) additional expansion capital needed to support new commercial activity.

Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives.

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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, 2023, we had a $311.6 million working capital deficit, which we define as the amount by which current liabilities exceed current assets.

Our working capital deficit was primarily due to the outstanding commercial paper borrowings being classified as short-term debt on the consolidated balance sheet.

As of December 31, 2023, there was $1.4 billion in effective borrowing capacity under the RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for our commercial paper program.

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.

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_________________________________________________________________________________________

(1) For the years ended December 31, 2023 and 2022, included $13.6 million and $5.6 million, respectively, of capitalized interest.

Acquisitions for the year ended December 31, 2023, include the acquisition of Meritage.

Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex.

(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 $247.9 million for the year ended December 31, 2023, primarily due to increases of (i) $130.4 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III and engineering and equipment milestone payments for the North Loving Plant, and pipeline projects, (ii) $55.0 million at the DBM water systems due to construction of additional water - disposal wells and facilities, pipeline build-out, and replacement projects, (iii) $39.0 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects, (iv) $10.0 million related to the acquisition of Meritage, (v) $9.9 million at the DJ Basin oil system due to an increase in pipeline projects, and (vi) $8.3 million at the DJ Basin complex due to an increase in well connection and pipeline projects.

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.

Historical cash flow .

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Operating activities .

Net cash provided by operating activities decreased for the year ended December 31, 2023, primarily due to (i) lower distributions from equity investments, (ii) higher interest expense, and (iii) lower cash operating income.

These decreases were partially offset by the impact of changes in assets and liabilities.

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.

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Net cash used in investing activities for the year ended December 31, 2024, 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;

• $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;

• $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:

• $487.2 million of capital expenditures, primarily related to construction, expansion, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system;

• $40.1 million of cash paid for the acquisition of the remaining 50% interest in Ranch Westex;

• $9.6 million of capital contributions primarily paid to Red Bluff Express;

• $9.5 million of increases to materials and supplies inventory;

• $263.0 million in proceeds from the sale of our 15.00% interest in Cactus II;

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

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

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

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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;

• $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;

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• $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.

Net cash used in financing activities for the year ended December 31, 2022, primarily included the following:

• $1,015.0 million of repayments of outstanding borrowings under the RCF;

• $735.8 million of distributions paid to WES unitholders;

• $502.2 million to redeem the total principal amount outstanding of WES Operating’s 4.000% Senior Notes due 2022;

• $487.6 million of unit repurchases;

• $24.9 million of distributions paid to the noncontrolling interest owner of WES Operating;

• $10.7 million of distributions paid to the noncontrolling interest owner of Chipeta;

• $1,390.0 million of borrowings under the RCF, which were used for general partnership purposes and to redeem portions of certain of WES Operating’s senior notes;

• $2.2 million of increases in outstanding checks.

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 no senior note borrowings due within the next year and, as of December 31, 2023, have $1.4 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for WES Operating’s commercial paper program.

During the year ended December 31, 2023, WES Operating (i) completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029, (ii) completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033, (iii) entered into an amendment to our RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date, (iv) entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion (WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings), (v) purchased and retired $276.7 million of certain of its senior notes via open-market repurchases, and (vi) redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand.

In May 2023, Fitch Ratings upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” WES Operating’s senior unsecured debt ratings are now investment grade at Standard and Poor’s, Moody’s Investors Services, and Fitch Ratings.

As a result of the upgrade, annualized borrowing costs will decrease by $6.9 million on WES Operating’s senior notes that are subject to effective interest-rate adjustments from a change in credit rating.

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.

Finance lease liabilities.

WES has finance leases with third parties for equipment, vehicles, and an NGL pipeline in Wyoming.

As of December 31, 2023, we have future finance-lease payments of $7.7 million for 2024 and a total of $35.0 million in years thereafter.

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.

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Operating leases.

We have entered into operating leases for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors.

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.

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Offload commitments.

We have entered into offload agreements with third parties providing firm-processing capacity through 2025.

As of December 31, 2023, we have future minimum payments under offload agreements totaling $7.7 million for 2024 and a total of $3.4 million in years thereafter.

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 entered into transportation contracts with volume commitments on multiple pipelines through 2033.

As of December 31, 2023, we have estimated future minimum-volume-commitment fees totaling $11.3 million for 2024, and a total of $67.5 million in years thereafter.

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 .

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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 historic carrying value.

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.

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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 $52.9 million for the year ended December 31, 2023, and $20.6 million (which includes an other-than-temporary impairment expense of an equity investment) for the year ended December 31, 2022.

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 years ended December 31, 2023, 2022, and 2021.

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.

Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs.

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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

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis