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Item 7. Management’s Discussion and Analysis

2024-02-21 compared with 2023-02-22 · 164 added, 290 removed, 554 unchanged (45% 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.

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, 2023 (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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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 as an agent for our customers under certain contracts.

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.

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Significant financial and operational events during the year ended December 31, 2023, included the following:

• WES Operating redeemed the $502.2 million total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value.

• We repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased from Occidental, for an aggregate purchase price of $487.6 million.

In November 2022, the Board authorized an increase in the repurchase program from $1.0 billion to $1.25 billion.

• 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.

• WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033.

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

See Liquidity and Capital Resources within this Item 7 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 $276.7 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.

• 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.

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

• 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.

• Crude - oil and NGLs throughput attributable to WES totaled 676 MBbls/d for the year ended December 31, 2022, representing a 3% increase compared to the year ended December 31, 2021.

• Crude - oil and NGLs throughput attributable to WES totaled 652 MBbls/d for the year ended December 31, 2023, representing a 4% decrease compared to the year ended December 31, 2022.

• 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 $2.2 billion for the year ended December 31, 2022 representing a 12% increase compared to the year ended December 31, 2021.

• 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.

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 $1.32 per Mcf for the year ended December 31, 2022, representing a 6% increase compared to the year ended December 31, 2021.

• 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 $2.46 per Bbl for the year ended December 31, 2022, representing an 8% increase compared to the year ended December 31, 2021.

• Adjusted gross margin for produced - water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.94 per Bbl for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021.

• 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 crude - oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.48 per Bbl for the year ended December 31, 2023, representing a 1% increase 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 $0.83 per Bbl for the year ended December 31, 2023, representing a 12% decrease compared to the year ended December 31, 2022.

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

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2023 2022 Inc/

(Dec) 2020 Inc/

Throughput for natural-gas assets (MMcf/d)

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DJ Basin 1,322 1,331 (1) %

Powder River Basin 120 33 NM

Equity investments 466 483 (4) %

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DJ Basin 71 82 (13) %

Powder River Basin 5 — 100 %

Equity investments 333 373 (11) %

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1,029 853 21 %

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NM — Not meaningful

OUR OPERATIONS

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Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Commodity purchase and sale agreements .

Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership.

Accordingly, we no longer recognize service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC.

Year-over-year variances for the year ended December 31, 2021, include the following impacts related to this change (i) decrease of $45.9 million in Service revenues – fee based, (ii) decrease of $21.2 million in Product sales, and (iii) decrease of $67.1 million in Cost of product expense.

These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see Reconciliation of Non-GAAP Financial Measures within this Item 7).

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Gathering and processing agreements.

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See Risk Factors under Part I, Item 1A of this Form 10-K.

Weather-related impacts.

In February 2021, the U.S.

experienced winter storm Uri, bringing extreme cold temperatures, ice, and snow to the central U.S., including Texas, and in March 2021, Colorado experienced a historic blizzard.

Winter storm Uri adversely affected our volumes for approximately ten days and the blizzard in Colorado likewise disrupted our assets in that state.

We estimate the impact of these weather events reduced our net income and Adjusted EBITDA (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2) for the year ended December 31, 2021, by approximately $30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities.

We recognized long-lived asset and other impairments of $20.6 million, $30.5 million, and $203.9 million for the years ended December 31, 2022, 2021, and 2020, respectively.

During the year ended December 31, 2020, we also recognized a goodwill impairment of $441.0 million, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero.

For a description of impairments recorded, see Note 9—Property, Plant, and Equipment , Note 7—Equity Investments , and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses.

In December 2019, we executed several agreements with Occidental that enabled us to operate as a standalone business.

As a result, beginning in 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity.

Acquisitions and divestitures.

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.

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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.

In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located in Northeast Wyoming, to a third party.

During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed.

We received total proceeds of $8.0 million, $7.0 million in the fourth quarter of 2020 and $1.0 million when the sale closed in the second quarter of 2021, resulting in a net gain on sale of $5.4 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

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

We recognized long-lived asset and other impairments of $52.9 million and $20.6 million for the years ended December 31, 2023 and 2022, 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.

RESULTS OF OPERATIONS

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Operating income (loss) 1,379,563 1,587,888

Interest income – Anadarko note receivable — — 11,736

Interest expense (348,228) (333,939)

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(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, 2022” refer to the comparison of the year ended December 31, 2022, to the year ended December 31, 2021, and any increases or decreases “for the year ended December 31, 2021” refer to the comparison of the year ended December 31, 2021, to the year ended December 31, 2020.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2023” refer to the comparison of the year ended December 31, 2023, to the year ended December 31, 2022.

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 .

Year Ended December 31,

2023 2022 Inc/

(Dec) 2020 Inc/

Throughput for natural-gas assets (MMcf/d)

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Throughput attributable to noncontrolling interests (2)

156 155 1 % 159 (3) %

Total throughput attributable to WES for natural - gas assets

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Throughput attributable to noncontrolling interests (2)

14 13 8 % 14 (7) %

Total throughput attributable to WES for crude - oil and NGLs assets

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Throughput attributable to noncontrolling interests (2)

17 14 21 % 14 — %

Total throughput attributable to WES for produced - water assets

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(1) Represents our share of average throughput for investments accounted for under the equity method of accounting.

(2) For all periods presented, 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.

(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

Gathering, treating, and transportation throughput decreased by 57 MMcf/d for the year ended December 31, 2022, primarily due to (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021, and (ii) production declines in the areas around the Marcellus Interest systems.

These decreases were offset partially by higher volumes at the MIGC system.

Gathering, treating, and transportation throughput decreased by 77 MMcf/d for the year ended December 31, 2021, primarily due to (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021 and (ii) production declines and the impact of winter storm Uri at the Springfield gas - gathering system.

These decreases were offset partially by increased production in the area around the Marcellus Interest systems.

Processing throughput increased by 100 MMcf/d for the year ended December 31, 2022, primarily due to higher volumes at the West Texas complex due to increased production in the area.

This increase was offset partially by (i) lower volumes due to production declines in areas around the DJ Basin and Granger complexes and (ii) lower volumes at the Brasada complex due to downstream issues causing volumes to be diverted away from the plant during 2022.

Processing throughput decreased by 71 MMcf/d for the year ended December 31, 2021, primarily due to (i) lower production and the impact of winter storm Uri at the West Texas complex, (ii) the Granger straddle plant being held idle beginning in the third quarter of 2020, and (iii) lower volumes at the Granger and Brasada complexes due to production declines in the areas.

These decreases were offset partially by higher volumes at the DJ Basin complex primarily due to an additional third-party connection to Latham Train II beginning January 1, 2021.

Equity - investment throughput increased by 20 MMcf/d for the year ended December 31, 2022, primarily due to increased volumes on Red Bluff Express due to increased production in the area.

This increase was offset partially by (i) 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 (see Acquisitions and Divestitures within this Item 7), and (ii) decreased volumes at the Rendezvous system due to production declines in the area.

Equity - investment throughput increased by 18 MMcf/d for the year ended December 31, 2021, primarily due to increased volumes on Red Bluff Express and at the Mi Vida plant, partially offset by (i) decreased volumes at the Rendezvous system due to production declines in the area and (ii) decreased volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020.

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.

Crude-oil and NGLs assets

Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes at the DBM oil system resulting from increased production in the area, partially offset by lower volumes at the DJ Basin oil system resulting from production declines in the area.

Gathering, treating, and transportation throughput decreased by 25 MBbls/d for the year ended December 31, 2021, primarily due to (i) lower volumes at the DJ Basin and Springfield oil systems resulting from production declines in the areas and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri.

Equity - investment throughput increased by 7 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes on FRP resulting from increased pipeline commitments.

This increase was offset partially by (i) lower volumes on the Cactus II pipeline, which was sold to two third parties in the fourth quarter of 2022, and (ii) decreased volumes on the Whitethorn pipeline.

Equity - investment throughput decreased by 15 MBbls/d for the year ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline.

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.

Produced-water assets

Gathering and disposal throughput increased by 136 MBbls/d for the year ended December 31, 2022, due to higher production and new third-party connections brought online during the fourth quarter of 2021 and in 2022.

Gathering and disposal throughput increased by 5 MBbls/d for the year ended December 31, 2021, due to increased volumes at the DBM water systems resulting from (i) higher production in the area, primarily during the second half of 2021, and (ii) new third-party connections brought online during the fourth quarter of 2021.

These increases were offset partially by the impact of winter storm Uri.

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.

Service Revenues

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thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

Service revenues – fee based $ 2,768,757 $ 2,602,053 6 %

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Service revenues – fee based

Service revenues – fee based increased by $139.2 million for the year ended December 31, 2022, primarily due to increases of (i) $63.1 million at the West Texas complex due to increased throughput, partially offset by a lower average gathering fee primarily due to a cost-of-service rate redetermination effective January 1, 2022, (ii) $59.7 million at the DBM oil system due to increased throughput, increased deficiency fees, and the treatment of lease revenue under the operating and maintenance agreement with Occidental that was terminated effective December 31, 2021, (iii) $44.8 million at the DBM water systems due to increased throughput and increased deficiency fees, (iv) $9.2 million at the Marcellus Interest systems due to a higher average gathering fee, partially offset by decreased throughput, and (v) $8.2 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021, partially offset by decreased throughput.

These increases were offset partially by decreases of (i) $31.7 million at the DJ Basin complex due to decreased throughput, partially offset by increased deficiency fees, and (ii) $4.9 million at the Springfield system primarily due to lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021.

Service revenues – fee based decreased by $121.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $45.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $36.4 million at the DBM oil system due to decreased throughput, including the impact of winter storm Uri, and lower lease revenue under the operating and maintenance agreement with Occidental, (iii) $23.4 million at the DJ Basin oil system due to an annual cost-of-service rate adjustment made during the fourth quarter of 2021 and decreased throughput, partially offset by a higher average gathering fee, (iv) $19.0 million at the DJ Basin complex due to decreased throughput on certain fee-based contracts, (v) $17.0 million at the Bison treating facility due to the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020, decreased throughput, and the sale of the facility to a third party during the second quarter of 2021, and (vi) $14.3 million at the DBM water systems due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021, partially offset by increased throughput.

These decreases were offset partially by increases of (i) $26.6 million at the West Texas complex due to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, partially offset by decreased throughput, including the impact of winter storm Uri, and (ii) $13.1 million at the Springfield system due to cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021.

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 – product based

Service revenues – product based increased by $127.1 million for the year ended December 31, 2022, primarily due to increases of (i) $81.4 million at the West Texas complex attributable to increases in pricing and volumes, along with changes in contract mix, (ii) $38.5 million at the DJ Basin complex due to changes in contract mix, and (iii) $4.2 million and $3.0 million at the DBM water systems and MGR assets, respectively, due to increases in pricing and volumes.

Service revenues – product based increased by $74.2 million for the year ended December 31, 2021, primarily due to increases of (i) $22.2 million at the West Texas complex due to an increase in electricity - related fees charged to customers during winter storm Uri, (ii) $20.5 million at the DJ Basin complex due to increased third - party volumes and average prices, and (iii) $8.9 million at the Granger complex, $8.5 million at the Hilight system, $6.9 million at the Chipeta complex, and $5.3 million at the MGR assets due to increased prices.

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.

Product Sales

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thousands except percentages and per-unit amounts 2023 2022 Inc/

(Dec) 2020 Inc/

Natural - gas sales

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Natural-gas sales

Natural - gas sales increased by $46.1 million for the year ended December 31, 2022, primarily due to increases of $45.7 million, $7.1 million, and $4.1 million at the West Texas complex, MGR assets, and Granger complex, respectively, attributable to increased average prices and volumes sold.

These increases were offset partially by a decrease of $14.1 million at the DJ Basin complex due to decreased volumes sold, partially offset by an increase in average prices.

Natural - gas sales increased by $52.6 million for the year ended December 31, 2021, primarily due to increases of (i) $49.0 million at the West Texas complex attributable to an increase in average prices, (ii) $9.6 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes sold, and (iii) $1.8 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

These increases were offset partially by decreases of $5.6 million at the DJ Basin complex and $4.9 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices.

NGLs sales increased by $62.0 million for the year ended December 31, 2022, primarily due to increases of (i) $31.4 million and $3.5 million at the DJ Basin and Granger complexes, respectively, due to an increase in average prices, partially offset by a decrease in volumes sold, and (ii) $14.5 million at the West Texas complex, $12.5 million at the Chipeta complex, and $4.4 million at the DBM water systems, attributable to increased average prices and volumes sold.

These increases were offset partially by a decrease of $5.1 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

NGLs sales increased by $99.8 million for the year ended December 31, 2021, primarily due to increases of (i) $73.8 million at the West Texas complex attributable to an increase in average prices, partially offset by a decrease in volumes sold, (ii) $22.3 million at the Chipeta complex and $11.3 million at the Granger complex attributable to increases in average prices, and (iii) $6.5 million at the DJ Basin complex attributable to an increase in average prices and volumes sold.

These increases were offset partially by a decrease of $23.0 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

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.

Equity Income, Net – Related Parties

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thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

Equity income, net – related parties $ 152,959 $ 183,483 (17) %

Equity income, net – related parties decreased by $21.2 million for the year ended December 31, 2022, primarily due to decreases of (i) $9.9 million at Saddlehorn due to decreases in revenues along with increases in operating expenses, (ii) $9.0 million at Ranch Westex, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition (see Acquisitions and Divestitures within this Item 7), (iii) $8.4 million at Whitethorn LLC due to decreases in volumes resulting in lower revenues, (iv) $6.5 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Acquisitions and Divestitures within this Item 7), and (v) $4.5 million at Mont Belvieu JV due to increases in operating expenses, partially offset by increases in revenue.

These decreases were offset partially by increases of $8.1 million and $7.6 million at TEP and FRP, respectively, due to increased volumes resulting in higher revenues.

Equity income, net – related parties decreased by $22.1 million for the year ended December 31, 2021, primarily due to decreases of (i) $30.8 million at Whitethorn LLC related to commercial activities and lower volumes, (ii) $4.7 million at White Cliffs due to lower volumes, and (iii) $4.0 million at Cactus II due to an increase in depreciation expense recorded in 2021.

These decreases were offset partially by increases of (i) $8.1 million at Mont Belvieu JV primarily from a load-reduction electricity credit received in the second quarter of 2021 related to winter storm Uri and (ii) $5.3 million and $4.6 million at Red Bluff Express and Saddlehorn, respectively, resulting from increased volumes.

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.

Cost of Product and Operation and Maintenance Expenses

1 unchanged sentence

thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

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

NGLs purchases 211,468 320,739 (34) %

Other (72,943) (11,655) NM (9,069) 29 %

Other (79,385) (72,943) (9) %

Cost of product 164,598 420,900 (61) %

1 unchanged sentence

Total Cost of product and Operation and maintenance expenses $ 927,128 $ 1,075,466 (14) %

_________________________________________________________________________________________

NM — Not meaningful

Residue purchases

Residue purchases increased by $26.4 million for the year ended December 31, 2022, primarily due to increases of (i) $15.3 million at the West Texas complex attributable to increased volumes purchased and average prices, as well as changes in contract mix during 2022, (ii) $10.1 million at the Chipeta complex due to increased volumes purchased and average prices, and (iii) $6.1 million and $4.7 million at the MGR assets and the Granger complex, respectively, primarily attributable to increased average prices.

These increases were offset partially by a decrease of $9.5 million at the DJ Basin complex primarily due to a change in contract mix during the second quarter of 2022.

Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.7 million at the West Texas complex, $6.7 million at the Chipeta complex, and $6.3 million at the Hilight system attributable to increases in average prices and (ii) $9.2 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes purchased.

These increases were offset partially by a decrease of $5.2 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

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.

NGLs purchases

NGLs purchases increased by $133.5 million for the year ended December 31, 2022, primarily due to increases of (i) $76.7 million at the West Texas complex due to increased volumes purchased and average prices, as well as a change in contract mix during the second quarter of 2022, (ii) $58.5 million at the DJ Basin complex attributable to increased average prices and a change in contract mix during the second quarter of 2022, and (iii) $4.2 million at the DBM water systems due to increased average prices and volumes purchased.

These increases were offset partially by a decrease of $4.6 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

NGLs purchases increased by $55.3 million for the year ended December 31, 2021, primarily due to increases of (i) $53.3 million at the West Texas complex, $13.7 million at the Chipeta complex, and $8.2 million at the Granger complex attributable to increases in average prices, (ii) $35.2 million at the DJ Basin complex attributable to an increase in average prices and volumes purchased, and (iii) $4.1 million at the Brasada complex attributable to an increase in average prices, partially offset by a decrease in volumes purchased.

These increases were offset partially by a decrease of $61.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

Other items decreased by $61.3 million for the year ended December 31, 2022, primarily due to decreases of $45.8 million and $21.0 million at the West Texas and DJ Basin complexes, respectively, attributable to changes in imbalance positions.

These decreases were offset partially by an increase of $5.5 million at the MGR assets attributable to changes in imbalance positions.

Other items decreased by $2.6 million for the year ended December 31, 2021, primarily due to a decrease of $25.4 million at the DJ Basin complex due to changes in imbalance positions, partially offset by increases of $16.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions.

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.

Operation and maintenance expense

Operation and maintenance expense increased by $73.3 million for the year ended December 31, 2022, primarily due to increases of (i) $15.4 million in chemicals and treating services, (ii) $14.8 million for maintenance and repair expense, (iii) $10.8 million for mechanical-integrity costs, (iv) $9.5 million for salaries and wages costs, (v) $9.4 million in regulatory and environmental expense, (vi) $9.1 million in utility expense, (vii) $7.3 million in land-related costs, and (viii) $4.2 million in water-disposal costs.

These increases were offset partially by a decrease of $8.0 million in contract labor and consulting expense.

Operation and maintenance expense increased by $0.4 million for the year ended December 31, 2021, primarily due to increases of (i) $21.0 million attributable to higher utility expense, (ii) $6.4 million due to higher field-area costs, and (iii) $4.0 million in vehicle costs.

These increases were offset partially by decreases of (i) $7.9 million attributable to lower contract labor and consulting expense, (ii) $6.7 million in water-disposal costs, (iii) $6.3 million due to lower regulatory and environmental expense, (iv) $5.9 million due to other operating costs, and (v) $4.5 million due to lower maintenance and repair 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.

Other Operating Expenses

1 unchanged sentence

thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

General and administrative $ 232,632 $ 194,017 20 %

3 unchanged sentences

52,884 20,585 157 %

Goodwill impairment — — — % 441,017 (100) %

Total other operating expenses $ 942,642 $ 875,526 8 %

General and administrative expenses

General and administrative expenses decreased by $1.5 million for the year ended December 31, 2022, primarily due to a decrease of $7.1 million in contract and consulting costs, primarily related to information technology services and fees incurred in 2021, partially offset by an increase of $5.9 million in personnel costs, including increased bonus-related expenses and other miscellaneous employee expenses.

General and administrative expenses increased by $39.8 million for the year ended December 31, 2021, primarily due to increases of (i) $23.7 million in personnel costs, including increased bonus-related contributions under our employee savings plan and equity-based compensation expense, and (ii) $16.9 million in contract and consulting costs primarily related to information technology services and fees.

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.

Property and other taxes

Property and other taxes increased by $14.3 million for the year ended December 31, 2022, primarily due to increases in the state assessed portion of ad valorem property values resulting in increases for the DJ Basin complex.

Property and other taxes decreased by $4.1 million for the year ended December 31, 2021, primarily due to ad valorem tax decreases at the West Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in the DJ Basin due to higher tax rates.

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.

Depreciation and amortization expense

Depreciation and amortization expense increased by $30.7 million for the year ended December 31, 2022, primarily due to (i) $14.2 million at the DJ Basin complex due to an acceleration of depreciation expense for revised service-life assumptions, (ii) $10.5 million resulting from capital projects being placed into service, (iii) $4.1 million of increased expense at the Hilight system, and (iv) $3.7 million at a transportation asset in Southwest Wyoming primarily as a result of a change in estimate for asset retirement obligations.

These increases were offset partially by a decrease in depreciation expense of $3.3 million at the MGR assets.

Depreciation and amortization expense increased by $60.5 million for the year ended December 31, 2021, primarily due to increases of (i) $33.6 million at the DJ Basin complex, primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system in the comparative prior period, (ii) $13.2 million at the Hilight system due to revisions in cost estimates related to asset retirement obligations, (iii) $8.2 million related to depreciation for capitalized information technology implementation costs related to the stand-up of WES as an independent organization, (iv) $7.3 million at the MGR assets due to an acceleration of depreciation expense, as well as revisions in cost estimates related to asset retirement obligations, and (v) $7.2 million at the West Texas complex resulting from capital projects being placed into service.

These increases were offset partially by a decrease of $17.4 million due to the sale of the Bison treating facility in the second quarter of 2021.

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.

Long-lived asset and other impairment expense

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.

Long - lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex.

Long-lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects

For further information on our equity investments and other-than-temporary impairments, see 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 Income – Anadarko Note Receivable and Interest Expense

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.

Interest Expense

Year Ended December 31,

thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

Interest income – Anadarko note receivable $ — $ — — % $ 11,736 (100) %

Long - term and short - term debt

4 unchanged sentences

Interest expense $ (348,228) $ (333,939) 4 %

Interest income

Interest income - Anadarko note receivable decreased by $11.7 million for the year ended December 31, 2021, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020.

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Interest expense

Interest expense decreased by $42.6 million for the year ended December 31, 2022, primarily due to decreases of (i) $21.3 million primarily due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 and 5.375% Senior Notes due 2021 during the second quarter of 2022 and first quarter of 2021, respectively, (ii) $16.8 million due to credit-rating related interest rate changes on the 4.050% Senior Notes due 2030 and 5.250% Senior Notes due 2050, (iii) $13.5 million due to credit-rating related interest rate changes and a lower outstanding balance on the 3.100% Senior Notes due 2025, and (iv) $2.7 million due to a lower outstanding balance on the 3.950% Senior Notes due 2025, a portion of which was repaid during the third quarter of 2021.

These decreases were offset partially by an increase of $13.6 million due to higher outstanding borrowings and average interest rates under the RCF during 2022.

Interest expense decreased by $3.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $21.2 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 during the first quarter of 2021, (ii) $5.7 million due to lower outstanding balances on the 4.000% Senior Notes due 2022, Floating Rate Notes due 2023, 3.950% Senior Notes due 2025, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021, and (iii) $3.6 million due to lower outstanding borrowings under the RCF in 2021.

These decreases were offset partially by (i) an increase of $26.4 million in additional interest incurred from higher effective interest rates resulting from credit - rating downgrades on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and (ii) a decrease of $1.2 million in capitalized interest due to decreased capital expenditures.

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.

See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.

Income Tax Expense (Benefit)

Other Income (Expense), Net

Year Ended December 31,

thousands except percentages 2023 2022 Inc/

(Dec) 2020 Inc/

Income (loss) before income taxes $ 1,255,643 $ 934,192 34 % $ 522,850 79 %

Income tax expense (benefit) 4,187 (9,807) (143) % 5,998 NM

Effective tax rate — % NM 1 %

Other income (expense), net $ 5,679 $ 1,603 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.

Income Tax Expense (Benefit)

We are not a taxable entity for U.S.

2 unchanged sentences

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

For the years ended December 31, 2022 and 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability.

For the year ended December 31, 2021, the variance from the federal statutory rate was primarily impacted by a state margin rate reduction associated with Occidental’s settlement of state audit matters and our Texas margin tax liability.

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

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

2 unchanged sentences

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, and (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.

The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are reimbursed by certain customers (recorded as revenue with an offset recorded as Operation and maintenance expense).

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.

35 unchanged sentences

_________________________________________________________________________________________

(1) For all periods presented, 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.

To facilitate investor and industry analyst comparisons between us and our peers, 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 .

(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.

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,

7 unchanged sentences

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

1.05 0.98 0.95

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

1.38 1.17 1.37

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

0.79 0.76 0.82

Adjusted gross margin

6 unchanged sentences

Per - Mcf Adjusted gross margin for natural - gas assets (3)

1.32 1.24 1.16

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (3)

2.46 2.28 2.54

Per - Bbl Adjusted gross margin for produced - water assets (3)

_________________________________________________________________________________________

(1) Excludes corporate-level depreciation and amortization.

14 unchanged sentences

Impairments 52,884 20,585

20,585 30,543 644,906

Other expense 1,739 555

2 unchanged sentences

Equity income, net – related parties 152,959 183,483

Interest income – Anadarko note receivable — — 11,736

Other income 6,976 1,648

Income tax benefit — 14,210 4,280

Adjusted EBITDA attributable to noncontrolling interests (1)

8 unchanged sentences

Other (income) expense, net (5,679) (1,603)

Cash paid to settle interest - rate swaps

Distributions from equity investments in excess of cumulative earnings – related parties 39,104 63,897

11 unchanged sentences

_________________________________________________________________________________________

(1) Includes goodwill impairment for the year ended December 31, 2020.

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

(2) For all periods presented, 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.

Year Ended December 31,

12 unchanged sentences

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 $245.2 million for the year ended December 31, 2022, due to a $374.6 million increase in total revenues and other, partially offset by (i) a $98.6 million increase in cost of product and (ii) a $30.7 million increase in depreciation and amortization.

Gross margin decreased by $90.2 million for the year ended December 31, 2021, due to (i) a $134.2 million increase in cost of product and (ii) a $60.5 million increase in depreciation and amortization.

These amounts were offset partially by a $104.6 million increase in total revenues and other.

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.

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 $307.5 million for the year ended December 31, 2022, primarily due to (i) a $374.6 million increase in total revenues and other, (ii) a $103.6 million increase in gain (loss) on divestiture and other, net, and (iii) a $42.6 million decrease in interest expense.

These amounts were offset partially by a $205.4 million increase in total operating expenses.

Net income (loss) increased by $427.1 million for the year ended December 31, 2021, primarily due to (i) a $383.5 million decrease in total operating expenses and (ii) a $104.6 million increase in total revenues and other.

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 cash provided by operating activities.

3 unchanged sentences

thousands except percentages and per-unit amounts 2023 2022 Inc/

(Dec) 2020 Inc/

Adjusted gross margin $ 2,963,847 $ 2,925,475 1 %

11 unchanged sentences

Adjusted gross margin.

Adjusted gross margin increased by $258.0 million for the year ended December 31, 2022, primarily due to (i) strong plant performance and contract mix leading to increased product recoveries, coupled with higher commodity prices and increased throughput at the West Texas complex, partially offset by a lower average gathering fee primarily due to a cost-of-service rate redetermination effective January 1, 2022, (ii) increased throughput and deficiency fee revenues at the DBM water and DBM oil systems, (iii) a higher average gathering fee at the Marcellus Interest systems, partially offset by decreased throughput, and (iv) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021 at the DJ Basin oil system (see Revenue and cost of product under 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), partially offset by decreased throughput.

These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC and (ii) lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021 at the Springfield system.

Adjusted gross margin decreased by $50.7 million for the year ended December 31, 2021, primarily due to (i) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, (ii) a decrease in distributions from Whitethorn LLC and Cactus II, (iii) decreased throughput and an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system (see Revenue and cost of product under 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), (iv) the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020 and decreased throughput at the Bison treating facility, which was sold to a third party during the second quarter of 2021, (v) a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the DBM water systems, and (vi) decreased throughput on certain fee-based contracts at the DJ Basin complex.

These decreases were offset partially by (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex, (ii) cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021, at the Springfield system, and (iii) an increase in distributions from Red Bluff Express and Ranch Westex.

Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 for the year ended December 31, 2022, primarily due to strong plant performance and contract mix leading to increased product recoveries, coupled with higher commodity prices and increased throughput at the West Texas complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets.

Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 for the year ended December 31, 2021, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex and (ii) a higher cost - of - service rate effective January 1, 2021, at the Springfield system.

These increases were offset partially by decreased throughput on certain fee-based contracts 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 $0.18 for the year ended December 31, 2022, primarily due to (i) increased throughput and increased deficiency fee revenues at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021 at the DJ Basin oil system, and (iii) an increase in distributions from Cactus II.

These increases were offset partially by (i) lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021 at the Springfield system, (ii) a decrease in distributions from Saddlehorn and Whitethorn LLC, and (iii) increased throughput on FRP, which has a lower - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets.

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets decreased by $0.26 for the year ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system and (ii) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets.

These decreases were offset partially by a higher cost - of - service rate effective January 1, 2021, at the Springfield system.

Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021.

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 EBITDA.

Adjusted EBITDA increased by $181.3 million for the year ended December 31, 2022, primarily due to a $374.6 million increase in total revenues and other.

This amount was offset partially by (i) a $98.4 million increase in cost of product expense (net of lower of cost or market inventory adjustments), (ii) a $73.3 million increase in operation and maintenance expenses, (iii) a $14.3 million increase in property taxes, and (iv) a $4.9 million decrease in distributions from equity investments.

Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments.

These amounts were offset partially by (i) a $104.6 million increase in total revenues and other and (ii) a $4.1 million decrease in property taxes.

The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

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.

Free cash flow.

Free cash flow decreased by $221.7 million for the year ended December 31, 2022, primarily due to (i) a $173.6 million increase in capital expenditures, (ii) a $65.4 million decrease in net cash provided by operating activities, and (iii) a $5.2 million increase in contributions to equity investments.

These amounts were offset partially by a $22.5 million increase in distributions from equity investments in excess of cumulative earnings.

Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings.

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.

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

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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 crude-oil, natural-gas, and NGLs prices.

Crude - oil, natural - gas, and NGLs prices can fluctuate significantly, and have done so over time.

Commodity - price fluctuations affect the level of our customers’ activities and our customers’ allocations of capital within their own asset portfolios.

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.

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, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021, and prices during the year ended December 31, 2022, ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022.

The extent and duration of the recent commodity - price volatility cannot be predicted.

To the extent producers continue with development plans in our areas of operation, we intend to continue to connect new wells or production facilities to our systems to maintain or increase throughput on our systems and mitigate the impact of production declines.

However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers, any capacity constraints, and the availability of downstream-takeaway alternatives.

In some cases, we take ownership of volumes at the tailgate of our plants based on certain contractual arrangements with our producer customers, which introduces additional commodity-price exposure.

Additionally, we intend to continue to evaluate the crude - oil, NGLs, and natural - gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

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 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.

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.

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Impact of inflation and supply-chain disruptions.

Although inflation in the United States has been relatively low in recent years, the U.S.

economy currently is experiencing 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 bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S.

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 labor, materials, fuel, and services, which has increased our operating costs and capital expenditures.

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.

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Impact of interest rates.

Overall, short- and long-term interest rates increased during 2021 and have continued to increase during 2022, resulting in increased interest expense on RCF borrowings and the Floating - Rate Senior Notes.

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.

Any future increases in interest rates likely will result in additional increases in financing costs.

Additionally, as with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.

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.

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

Our sources of liquidity as of December 31, 2022, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities.

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.

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 depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board on a quarterly basis.

We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions.

However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to fund equity or other short - term working capital 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.

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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.

We have made cash distributions to our unitholders each quarter since our initial public offering in 2012.

The Board declared a cash distribution to unitholders for the fourth quarter of 2023 of $0.575 per unit, or $223.4 million in the aggregate.

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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 levels (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.

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 February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024.

In November 2022, the Board authorized an increase in the program to $1.25 billion.

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.

The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.

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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, 2022, we repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased

from Occidental, for an aggregate purchase price of $487.6 million.

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.

For the year ended December 31, 2023, we estimate that our total capital expenditures will be between $575.0 million to $675.0 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 coordinates our capital expenditures and equity requirements with expected cash inflows and projected debt-service requirements.

We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance maturing debt balances with longer - term debt issuances.

For the year ended December 31, 2024, capital expenditures are expected to range between $700.0 million to $850.0 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.

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.

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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 Floating-Rate Senior Notes being classified as short-term debt on the consolidated balance sheet as of December 31, 2022.

As of December 31, 2022, there was $1.6 billion available for borrowing under the RCF.

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.

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, 2022, 2021, and 2020, included $5.6 million, $3.6 million, and $4.8 million, respectively, of capitalized interest.

Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures within this Item 7).

Capital expenditures increased by $173.6 million for the year ended December 31, 2022, primarily due to increases of (i) $119.9 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III, and pipeline projects, (ii) $31.8 million at the DBM water systems due to construction of additional water - disposal wells and facilities and pipeline projects, and (iii) $17.3 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects.

These increases were offset partially by a decrease of $8.9 million at the DJ Basin oil system, primarily related to a decrease in pipeline projects.

Capital expenditures decreased by $109.9 million for the year ended December 31, 2021, primarily due to decreases of (i) $43.9 million at the DJ Basin complex primarily related to the completion of Latham Train II that commenced operations in the first quarter of 2020, and decreases in pipeline, well connection, and compression projects, (ii) $22.6 million at the West Texas complex primarily attributable to decreases in facility expansion, (iii) $15.7 million at the DBM oil system primarily related to the completion of the Loving ROTF Trains III and IV that commenced operations during the first and third quarters of 2020, respectively, and decreases in pipeline and well connection projects, (iv) $10.0 million at the DBM water systems primarily due to reduced construction of additional water - disposal facilities and gathering projects, and (v) $4.8 million at the DJ Basin oil system primarily related to decreases in pipeline projects.

(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.

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.

Historical cash flow .

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Operating activities .

Net cash provided by operating activities decreased for the year ended December 31, 2022, primarily due to (i) the impact of changes in assets and liabilities and (ii) lower distributions from equity investments.

These decreases were partially offset by (i) higher cash operating income and (ii) lower interest expense.

Net cash provided by operating activities increased for the year ended December 31, 2021, primarily due to (i) the impact of changes in assets and liabilities, (ii) cash paid during the year ended December 31, 2020, to settle interest-rate swaps, and (iii) lower interest expense.

These increases were offset partially by (i) lower cash operating income, (ii) lower distributions from equity-investment earnings, and (iii) lower interest income.

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.

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, 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;

• $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;

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

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

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• $4.4 million of capital contributions primarily paid to Cactus II;

• $41.4 million of distributions received from equity investments in excess of cumulative earnings;

• $11.1 million of decreases to materials and supplies inventory;

• $8.0 million related to the sale of the Bison treating facility.

Net cash used in investing activities for the year ended December 31, 2020, included the following:

• $423.6 million of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM water systems, 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;

• $19.4 million of capital contributions primarily paid to Cactus II and FRP for construction activities;

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

• $63.9 million of distributions received from equity investments in excess of cumulative earnings.

• $20.3 million in proceeds primarily from the sale of Fort Union.

Financing activities .

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• $1,495.0 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;

• $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;

• $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.

• $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;

• $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:

• $533.8 million of distributions paid to WES unitholders;

• $521.9 million to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer;

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

• $431.1 million to redeem the total principal amount outstanding of WES Operating’s 5.375% Senior Notes due 2021;

• $217.5 million of unit repurchases;

• $21.6 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020;

• $15.0 million of distributions paid to the noncontrolling interest owner of WES Operating;

• $9.1 million of distributions paid to the noncontrolling interest owner of Chipeta;

• $480.0 million of borrowings under the RCF, which were used for general partnership purposes and to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer;

• $8.5 million of contributions from related parties.

Net cash used in financing activities for the year ended December 31, 2020, included the following:

• $3.0 billion of repayments of outstanding borrowings under the Term loan facility;

• $600.0 million of repayments of outstanding borrowings under the RCF;

• $735.8 million of distributions paid to WES unitholders;

• $203.9 million to purchase and retire portions of WES Operating’s 5.375% Senior Notes due 2021, 4.000% Senior Notes due 2022, and Floating-Rate Senior Notes via open-market repurchases;

• $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;

• $14.2 million of finance lease payments;

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

• $3.5 billion of net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued in January 2020, which were used to repay the $3.0 billion outstanding borrowings under the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes;

• $220.0 million of borrowings under the RCF, which were used for general partnership purposes;

• $20.7 million of increases in outstanding checks due mostly to ad valorem tax payments made at the end of the year;

• $20.0 million of a one-time cash contribution from Occidental received in January 2020, pursuant to the Services Agreement, for anticipated transition costs required to establish stand-alone human resources and information technology functions.

• $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, 2023, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $346.3 million in 2024.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating Senior Notes .

In mid - January 2020, WES Operating issued the Fixed - Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and the Floating - Rate Senior Notes due 2023.

Including the effects of the issuance prices, underwriting discounts, and interest - rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 3.790%, 4.671%, and 5.869%, respectively, at December 31, 2022.

The interest rate on the Floating - Rate Senior Notes was 5.04% at December 31, 2022.

The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating.

In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-” and in March 2022, Moody’s upgraded WES Operating’s long-term debt from “Ba2” to “Ba1.” As a result of these upgrades, annualized borrowing costs decreased by $15.7 million.

During the second quarter of 2022, WES Operating (i) redeemed the total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value and (ii) purchased and retired $1.4 million of the 3.100% Senior Notes due 2025 via open-market repurchases.

As of December 31, 2022, the Floating-Rate Senior Notes were classified as short-term debt on the consolidated balance sheet, and in January 2023, WES Operating redeemed the total principal amount outstanding at par value with cash on hand.

As of December 31, 2022, WES Operating was in compliance with all covenants under the relevant governing indentures.

We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt 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.

The amounts involved may be material.

Revolving credit facility.

In June 2022, WES Operating entered into an amendment to its $2.0 billion RCF, which is expandable to a maximum of $2.5 billion, to, among other things, (i) extend the maturity date applicable to the loans and commitments of certain lenders totaling $1.6 billion to February 2026, (ii) provide for the ability of WES Operating to extend the maturity date by one year on up to two additional occasions, (iii) provide that loans under the RCF with a fixed interest rate for a specified period bear interest based on SOFR instead of LIBOR, and (iv) include an additional level of pricing if WES Operating’s senior unsecured debt rating is less than or equal to BB/Ba2/BB (S&P / Moody’s Investors Service / Fitch Ratings).

The non - extending lender’s commitments mature in February 2025 and represent $400.0 million out of $2.0 billion of total commitments from all lenders.

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

A required quarterly facility fee is paid ranging from 0.125% to 0.300% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.

As of December 31, 2022, there were $375.0 million of outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $1.6 billion of available borrowing capacity under the RCF.

As of December 31, 2022, the interest rate on any outstanding RCF borrowings was 5.92% and the facility - fee rate was 0.25%.

As of December 31, 2022, the outstanding borrowings under the RCF were classified as long-term debt on the consolidated balance sheet and WES Operating was in compliance with all covenants under the RCF.

The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related - party transactions and use proceeds other than for partnership purposes.

The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most - recent four - consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270 - day period immediately following certain acquisitions.

As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited.

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.

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.

During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles.

Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification.

As a result, these leases were classified as operating leases.

As of December 31, 2022, we have future finance-lease payments of $2.7 million in 2023 and a total of $5.3 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.

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.

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 properties, 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.

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Operating leases.

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

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.

As of December 31, 2023, we have future operating-lease payments of $11.6 million in 2024 and a total of $67.7 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.

Pipeline commitments.

In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline.

As of December 31, 2022, we have estimated future minimum-volume-commitment fees of $3.7 million in 2023 and a total of $7.4 million in years thereafter.

Offload commitments.

During the year ended December 31, 2022, we entered into offload agreements with third parties providing firm-processing capacity through 2025.

As of December 31, 2022, we have future minimum payments under offload agreements totaling $16.8 million in 2023 and a total of $10.5 million in years thereafter.

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.

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.

Credit risk .

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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 rights to request adequate assurance.

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.

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Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values.

Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment.

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 production forecasts and revenue, capital, and operating expense estimates.

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.

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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 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.

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 $20.6 million, $30.5 million, and $203.9 million (all of which include an other-than-temporary impairment expense of an equity investment) for the years ended December 31, 2022, 2021, and 2020, respectively.

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.

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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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What changed 10-K

Item 7. Management’s Discussion and Analysis