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Item 7. Management’s Discussion and Analysis

2023-02-22 compared with 2022-02-23 · 242 added, 246 removed, 602 unchanged (45% of the section changed)

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Significant financial and operational events during the year ended December 31, 2022, included the following:

• WES Operating redeemed the total principal amount outstanding of $431.1 million of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture.

• WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer.

• We repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million.

• Our fourth - quarter 2021 per - unit distribution of $0.32700 increased $0.004 from the third - quarter 2021 per - unit distribution of $0.32300.

• Natural - gas throughput attributable to WES totaled 4,148 MMcf/d for the year ended December 31, 2021, representing a 3% decrease compared to the year ended December 31, 2020.

• Crude - oil and NGLs throughput attributable to WES totaled 659 MBbls/d for the year ended December 31, 2021, representing a 6% decrease compared to the year ended December 31, 2020.

• 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.

• Our fourth - quarter 2022 per - unit distribution is unchanged from the third-quarter 2022 per-unit distribution of $0.50000.

• 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.

• Natural - gas throughput attributable to WES totaled 4,210 MMcf/d for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021.

• 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.

• Produced - water throughput attributable to WES totaled 836 MBbls/d for the year ended December 31, 2022, representing a 19% increase compared to the year ended December 31, 2021.

• Gross margin was $2.0 billion for the year ended December 31, 2021, representing a 4% decrease compared to the year ended December 31, 2020.

See Key Performance Metrics within this Item 7.

• Adjusted gross margin for natural - gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $1.24 per Mcf for the year ended December 31, 2021, representing a 7% increase compared to the year ended December 31, 2020.

• Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $2.28 per Bbl for the year ended December 31, 2021, representing a 10% decrease compared to the year ended December 31, 2020.

• Adjusted gross margin for produced - water assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.93 per Bbl for the year ended December 31, 2021, representing a 5% decrease compared to the year ended December 31, 2020.

• 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.

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.

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

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

For example, for the year ended December 31, 2021, our West Texas and DJ Basin assets provided (i) 47% and 35%, respectively, of Total revenues and other, (ii) 33% and 36%, respectively, each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 60% and 29%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.

For example, for the year ended December 31, 2022, our West Texas and DJ Basin assets provided (i) 52% and 32%, respectively, of Total revenues and other, (ii) 38% and 34%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 62% and 26%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.

For the year ended December 31, 2022, 55% of Total revenues and other, 35% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 80% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.

While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market.

In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payment, and/or cost-of-service commitments under certain of our contracts.

In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts.

For the year ended December 31, 2022, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose.

This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.

We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to delay drilling or shut-in production in certain areas, which would reduce the volumes of hydrocarbons available to our systems.

We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to alter drilling or production schedules in certain areas, which could cause variability in the volumes of hydrocarbons available to our systems.

We also bear limited commodity-price risk through the settlement of imbalances.

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

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

Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see in Key Performance Metrics within this Item 7).

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

Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7).

Throughput is a significant operating variable that we use to assess our ability to generate revenues.

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We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations.

Operating and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, fleet management, contract services, utility costs, and services provided to us or on our behalf.

Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services.

General and administrative expenses .

To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget.

Capital expenditures .

Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure.

Capital expenditures associated with growth and maintenance projects is closely monitored.

Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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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.

Year-over-year variances for the year ended December 31, 2020, include the following impacts related to this change (i) decrease of $130.9 million in Service revenues – fee based, (ii) decrease of $29.7 million in Product sales, and (iii) decrease of $160.6 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 Key Performance Metrics within this Item 7).

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.

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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.

In addition, certain of our natural-gas processing agreements provide our producer customers with the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof).

Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows.

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

Weather-related impacts.

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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 Key Performance Metrics 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 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.

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General and administrative expenses.

On December 31, 2019, we entered into the December 2019 Agreements, which helped facilitate our ability to operate more independently from Occidental.

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.

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.

Noncontrolling interests.

For periods subsequent to Merger completion, our noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating.

For periods prior to Merger completion, our noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, and (iv) the Class C units issued by WES Operating to a subsidiary of Anadarko as part of the funding for the acquisition of DBM.

Acquisitions and divestitures.

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

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

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

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

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.

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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.

In February 2019, WES Operating acquired AMA from Anadarko.

In January 2019, we acquired a 30% interest in Red Bluff Express.

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

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(1) Represents the 14.81% share of average Fort Union throughput (until divested in October 2020), 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput.

(2) For all periods presented, includes (i) the 2.0% Occidental subsidiary - owned limited partner interest in WES Operating and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

(3) Represents the 10% share of average White Cliffs throughput;

25% share of average Mont Belvieu JV throughput;

20% share of average TEG, TEP, Whitethorn, and Saddlehorn throughput;

33.33% share of average FRP throughput;

and 15% share of average Panola and Cactus II throughput.

(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.

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 areas around the Marcellus Interest systems.

Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year ended December 31, 2020, primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison treating facility and 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.

Processing throughput decreased by 52 MMcf/d for the year ended December 31, 2020, primarily due to (i) third-party volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 and the plant being held idle during the third and fourth quarters of 2020, (ii) lower throughput at the Chipeta complex due to production declines in the area and a third-party contract that terminated during the fourth quarter of 2019, and (iii) lower throughput at the Red Desert complex due to production declines in the area.

These decreases were offset partially by (i) increased production in areas around the West Texas and DJ Basin complexes, (ii) the start-up of Latham Train II at the DJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at the West Texas complex in March 2019.

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.

Equity-investment throughput increased by 47 MMcf/d for the year ended December 31, 2020, primarily due to increased volumes on Red Bluff Express resulting from increased production in the area.

This increase was offset partially by (i) decreased third-party volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the Rendezvous system due to production declines in the area.

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.

Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2020, primarily due to increased throughput at the DBM oil system with the commencement of Loving ROTF Trains III and IV operations during the first and third quarters of 2020, respectively, and increased production, partially offset by lower throughput at the DJ Basin oil system due to production declines in the area.

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.

Equity-investment throughput increased by 38 MBbls/d for the year ended December 31, 2020, primarily due to (i) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020.

These increases were offset partially by decreased volumes on the Whitethorn pipeline.

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.

Gathering and disposal throughput increased by 156 MBbls/d for the year ended December 31, 2020, due to increased throughput at the DBM water systems resulting from additional (i) production, (ii) water-disposal facilities, and (iii) offload connections that increased capacity of the systems.

Service Revenues

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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 $196.1 million for the year ended December 31, 2020, primarily due to increases of (i) $98.1 million at the West Texas complex and $97.9 million at the DJ Basin complex from increased throughput, (ii) $63.6 million at the DBM oil system from increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, (iii) $59.3 million at the DBM water systems from increased throughput, and (iv) $21.4 million at the Springfield system due to annual cost-of-service rate adjustments that increased revenue in the fourth quarter of 2020 and decreased revenue in the fourth quarter of 2019, partially offset by decreased volumes.

These increases were offset partially by a decrease of $130.9 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).

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 $21.8 million for the year ended December 31, 2020, primarily due to (i) decreased third-party volumes at the DJ Basin complex and MGR assets and (ii) decreased pricing across several systems.

Product 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.

Natural-gas sales decreased by $36.0 million for the year ended December 31, 2020, primarily due to decreases of (i) $15.2 million at the DJ Basin complex attributable to a decrease in average prices, (ii) $9.8 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (iii) $6.2 million at the Hilight system resulting from an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown, and (iv) $2.6 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).

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).

NGLs sales decreased by $111.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $34.0 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (ii) $27.1 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), (iii) $17.7 million at the DJ Basin complex attributable to a decrease in average prices, and (iv) $14.7 million at the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average prices and volumes sold.

Equity Income, Net – Related Parties

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Equity income, net – related parties $ 183,483 $ 204,645 (10) % $ 226,750 (10) %

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 $10.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $38.8 million from Whitethorn LLC related to commercial activities and decreased volumes and (ii) $4.2 million from decreased rates at White Cliffs.

These decreases were offset partially by increases of (i) $11.4 million related to the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) $5.5 million at TEP, $5.3 million at Ranch Westex, $5.1 million at FRP, and $5.1 million at Red Bluff Express resulting from increased volumes.

Cost of Product and Operation and Maintenance Expenses

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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 $35.4 million for the year ended December 31, 2020, primarily due to decreases of (i) $21.1 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), (ii) $11.3 million at the DJ Basin complex attributable to average-price decreases, and (iii) $4.3 million at the MGR assets attributable to average-price and purchased-volume decreases.

These decreases were offset partially by an increase of $3.2 million at the Chipeta complex primarily due to purchased-volume and average-price increases.

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).

NGLs purchases decreased by $199.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $139.5 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) $32.6 million at the West Texas complex attributable to average-price decreases, partially offset by purchased-volume increases, (iii) $13.8 million at the Brasada complex attributable to purchased-volume decreases, partially offset by average-price increases, and (iv) $6.9 million at the Chipeta complex attributable to average-price and purchased-volume decreases.

Other items increased by $24.0 million for the year ended December 31, 2021, primarily due to increases of $29.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions, partially offset by a decrease of $11.7 million at the DJ Basin complex due to changes in imbalance positions.

Other items decreased by $20.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $10.3 million at the West Texas complex due to changes in imbalance positions and (ii) $10.0 million at the DJ Basin complex due to a decrease in transportation costs and changes in imbalance positions.

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.

Operation and maintenance expense

Operation and maintenance expense increased by $0.4 million for the year ended December 31, 2021, primarily due to an increase of $7.6 million at the West Texas complex, mainly attributable to increased field-related expenses, as well as an increase in utilities expense resulting from the impact of winter storm Uri, partially offset by a decrease of $6.6 million at the Springfield system primarily due to decreased environmental and regulatory expenses.

Operation and maintenance expense decreased by $60.3 million for the year ended December 31, 2020, primarily as a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $34.2 million at the West Texas complex primarily resulting from decreased salaries and wages, contract labor and consulting services, and surface maintenance and plant repairs expense, (ii) $6.1 million and $3.3 million at the Springfield and DBM oil systems, respectively, primarily due to decreased salaries and wages and surface maintenance and plant repairs expense, partially offset by increases in other field expenses, (iii) $4.6 million at the Chipeta complex primarily attributable to decreased surface maintenance and plant repairs and utilities expense, and (iv) $3.2 million and $2.4 million at the Hilight system and Granger complex, respectively, primarily due to decreased salaries and wages, surface maintenance and plant repairs, and safety 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.

Other Operating Expenses

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Long - lived asset and other impairments

30,543 203,889 (85) % 6,279 NM

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

20,585 30,543 (33) % 203,889 (85) %

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

Total other operating expenses $ 875,526 $ 841,988 4 % $ 1,360,101 (38) %

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 $41.2 million for the year ended December 31, 2020, primarily due to (i) $21.2 million related to information technology services provided by Occidental to WES and (ii) $16.4 million in personnel costs primarily resulting from WES securing its own dedicated workforce as of December 31, 2019.

General and administrative expenses also increased by $6.0 million for the year ended December 31, 2020, primarily due to increases in corporate expenses and professional fees.

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

For the year ended December 31, 2019, General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements.

Effective with the December 2019 Agreements, WES began to incur such costs directly, or via direct charge from Occidental, pursuant to the terms of the Services Agreement.

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 increased by $7.0 million for the year ended December 31, 2020, primarily due to ad valorem tax increases of $6.5 million at the DJ Basin complex due to capital projects being placed into service, including the completion of Latham Train I in November 2019.

This increase was offset partially by ad valorem tax decreases in Utah and West Texas due to lower valuations and lower tax rates.

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 $7.8 million for the year ended December 31, 2020, primarily due to increases of (i) $11.9 million and $5.9 million at the West Texas complex and DBM oil system, respectively, resulting from capital projects being placed into service, (ii) $7.8 million of amortization expense related to finance leases, and (iii) $3.3 million for a pipeline in Wyoming due to revisions in cost estimates related to asset retirement obligations.

These amounts were offset partially by decreases of (i) $10.6 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 of $32.7 million, offset by increased depreciation expense of $22.1 million for capital projects being placed into service, (ii) $10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii) $5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020.

See Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations.

Long-lived asset and other impairment expense

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

Long-lived asset and other impairment expense for the year ended December 31, 2019, was primarily due to impairments of $4.9 million at the DJ Basin complex due to impairments of rights-of-way and 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.

Goodwill impairment expense

During the three months ended March 31, 2020, an interim goodwill impairment test was performed due to significant unit - price declines triggered by the combined impacts from the global outbreak of COVID - 19 and the oil - market disruption.

As a result of the interim impairment test, a goodwill impairment of $441.0 million was recognized for the gathering and processing reporting unit.

For additional information, see Note 10—Goodwill and Other Intangibles 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

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

Third parties

Long - term and short - term debt

$ (326,949) $ (366,570) (11) % $ (369,815) (1) %

Finance lease liabilities (861) (1,510) (43) % — NM

Finance lease liabilities (414) (861) (52) % (1,516) (43) %

Commitment fees and amortization of debt-related costs (12,212) (12,705) (4) % (13,501) (6) %

Capitalized interest 5,636 3,624 56 % 4,774 (24) %

Related parties

APCWH Note Payable — — — % (1,833) (100) %

Finance lease liabilities — (6) (100) % (137) (96) %

Interest expense $ (333,939) $ (376,512) (11) % $ (380,058) (1) %

Interest income

Interest income - Anadarko note receivable decreased by $11.7 million and $5.2 million for the years ended December 31, 2021 and 2020, respectively, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020.

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 $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 on March 1, 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.

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 $76.8 million for the year ended December 31, 2020, primarily due to (i) $150.9 million of interest incurred on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and Floating-Rate Senior Notes due 2023 that were issued in January 2020 and (ii) a decrease of $22.2 million in capitalized interest due to decreased capital expenditures.

These increases were offset partially by decreases of (i) $75.0 million that occurred as a result of the repayment and termination of the Term loan facility in January 2020 and (ii) $15.5 million due to lower outstanding borrowings under the RCF in 2020.

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

Other Income (Expense), Net

Year Ended December 31,

thousands except percentages 2021 2020 Inc/

(Dec) 2019 Inc/

Other income (expense), net $ (623) $ 1,025 (161) % $ (123,785) (101) %

Other income (expense), net increased by $124.8 million for the year ended December 31, 2020, primarily due to non-cash losses of $125.3 million on interest-rate swaps incurred during the year ended December 31, 2019.

All outstanding interest-rate swap agreements were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Income Tax Expense (Benefit)

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

Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax.

Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.

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.

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

KEY PERFORMANCE METRICS

Year Ended December 31,

thousands except percentages and per-unit amounts 2021 2020 Inc/

(Dec) 2019 Inc/

Adjusted gross margin for natural - gas assets

$ 1,882,726 $ 1,820,926 3 % $ 1,656,041 10 %

Adjusted gross margin for crude - oil and NGLs assets

547,134 647,390 (15) % 578,100 12 %

Adjusted gross margin for produced - water assets

237,656 249,889 (5) % 193,936 29 %

Adjusted gross margin 2,667,516 2,718,205 (2) % 2,428,077 12 %

Per - Mcf Adjusted gross margin for natural - gas assets (1)

1.24 1.16 7 % 1.07 8 %

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

2.28 2.54 (10) % 2.44 4 %

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

0.93 0.98 (5) % 0.97 1 %

Adjusted EBITDA 1,946,690 2,030,366 (4) % 1,719,090 18 %

Free cash flow 1,490,128 1,226,588 21 % 36,709 NM

_________________________________________________________________________________________

(1) Average for period.

Calculated as Adjusted gross margin for natural - gas assets, divided by total throughput (MMcf/d) attributable to WES for natural - gas assets.

(2) Average for period.

Calculated as Adjusted gross margin for crude - oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude - oil and NGLs assets.

(3) Average for period.

Calculated as Adjusted gross margin for produced - water assets, divided by total throughput (MBbls/d) attributable to WES for produced - water assets.

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

Adjusted gross margin.

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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).

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 .

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.

Adjusted gross margin increased by $290.1 million for the year ended December 31, 2020, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes and the DBM water systems, (ii) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system, (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, (iv) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020, and (v) annual cost-of-service rate adjustments at the Springfield system that increased revenues in the fourth quarter of 2020 and decreased revenues in the fourth quarter of 2019 (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).

These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC related to commercial activities and (ii) a decrease at the Hilight system resulting from lower throughput and an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown.

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-Mcf Adjusted gross margin for natural-gas assets increased by $0.09 for the year ended December 31, 2020, primarily due to increased throughput at the West Texas and DJ Basin complexes, which have higher-than-average per-Mcf margins as compared to our other natural-gas 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 crude-oil and NGLs assets increased by $0.10 for the year ended December 31, 2020, primarily due to (i) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020.

These increases were offset partially by a decrease in distributions from Whitethorn LLC related to commercial activities.

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 EBITDA.

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• the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities.

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.

Adjusted EBITDA increased by $311.3 million for the year ended December 31, 2020, primarily due to (i) a $256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a $60.3 million decrease in operation and maintenance expenses, (iii) a $26.4 million increase in total revenues and other, and (iv) a $14.0 million increase in distributions from equity investments.

These amounts were offset partially by (i) a $33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a $7.0 million increase 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).

Free cash flow.

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Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes.

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 increased by $1,189.9 million for the year ended December 31, 2020, primarily due to (i) a decrease of $765.7 million in capital expenditures, (ii) an increase of $313.3 million in net cash provided by operating activities, and (iii) a decrease of $109.0 million in contributions to equity investments.

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

Reconciliation of non-GAAP financial measures.

Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP.

The GAAP measure used by us that is most directly comparable to Adjusted gross margin is gross margin.

Net income (loss) and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA.

The GAAP measure used by us that is most directly comparable to Free cash flow is net cash provided by operating activities.

The GAAP measure that is most directly comparable to Adjusted gross margin is gross margin.

Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA.

The GAAP measure that is most directly comparable to Free cash flow is net cash provided by operating activities.

Our non - GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP.

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Adjusted gross margin $ 2,925,475 $ 2,667,516 $ 2,718,205

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(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.

Year Ended December 31,

thousands except per-unit amounts 2022 2021 2020

Gross margin for natural - gas assets (1)

$ 1,676,732 $ 1,536,163 $ 1,537,075

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

346,406 287,391 354,784

Gross margin for produced - water assets (1)

245,274 197,821 213,834

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

Adjusted gross margin for natural - gas assets

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286,106 237,656 249,889

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

1.32 1.24 1.16

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

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)

0.94 0.93 0.98

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(1) Excludes corporate-level depreciation and amortization.

(2) Average for period.

Calculated as Gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.

(3) Average for period.

Calculated as Adjusted Gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.

Year Ended December 31,

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Interest (income) expense, net 333,939 376,512 368,322

Uncontributed cash-based compensation awards — — (1,102)

Accretion and amortization of long - term obligations, net

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Other (income) expense, net (1,603) 623 (1,025)

623 (1,025) (1,549)

Cash paid to settle interest - rate swaps

— 25,621 107,685

Distributions from equity investments in excess of cumulative earnings – related parties 63,897 41,385 32,160

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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% Occidental subsidiary - owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests.

(3) Excludes net non-cash losses on interest-rate swaps of $25.6 million for the year ended December 31, 2019.

See Note 13—Debt and Interest Expense 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,

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Net cash provided by (used in) financing activities (1,398,532) (1,752,237) (844,204)

Gross margin.

Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenue s, Product Sales , Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).

Gross margin increased by $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.

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 cash provided by operating activities.

Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods.

KEY PERFORMANCE METRICS

Year Ended December 31,

thousands except percentages and per-unit amounts 2022 2021 Inc/

(Dec) 2020 Inc/

Adjusted gross margin $ 2,925,475 $ 2,667,516 10 % $ 2,718,205 (2) %

Per - Mcf Adjusted gross margin for natural - gas assets (1)

1.32 1.24 6 % 1.16 7 %

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (1)

2.46 2.28 8 % 2.54 (10) %

Per - Bbl Adjusted gross margin for produced - water assets (1)

0.94 0.93 1 % 0.98 (5) %

Adjusted EBITDA 2,127,973 1,946,690 9 % 2,030,366 (4) %

Free cash flow 1,268,463 1,490,128 (15) % 1,226,588 21 %

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(1) Average for period.

Calculated as Adjusted gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets.

Adjusted gross margin.

Adjusted gross margin increased by $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.

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 - 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.

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

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.

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.

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.

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

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the below - described key trends and uncertainties.

We expect our business to be affected by the below - described key trends and uncertainties.

Our expectations are based on assumptions made by us and information currently available to us.

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

During the first quarter of 2020, oil and natural - gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in demand resulting from the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19.

These market dynamics had an adverse impact on producers that provide throughput into our systems, and we experienced decreased throughput at many of our locations.

For example, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2020 ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, and 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.

Although commodity prices have rebounded to pre-pandemic levels, the extent and duration of the recent commodity - price volatility cannot be predicted, and potential impacts to our business include the following:

• We have exposure to increased credit risk to the extent any of our customers, including Occidental, is in financial distress.

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

• An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage 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) .

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

• As of December 31, 2021, it is reasonably possible that future commodity - price declines, prolonged depression of commodity prices, changes to producers’ drilling plans in response to lower prices, and potential producer bankruptcies could result in future long - lived asset impairments.

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 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.

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.

Liquidity and access to capital markets.

Historically, we have accessed the debt and equity capital markets to raise money to fund growth projects, acquisitions, and to refinance long-term debt.

In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions.

From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable.

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These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells.

In addition, in certain areas in which we operate, public protests of oil and gas operations are becoming more frequent.

In addition, in certain areas in which we operate, public protests of oil and gas operations are not uncommon.

The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets.

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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.

More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S.

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

A significant increase in inflation would raise our costs for labor, materials, and services, which could increase our operating costs and capital expenditures materially and negatively impact our financial results.

Continued inflation has raised our costs for 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.

To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates.

Overall, short- and long-term interest rates increased during 2021, but remained low relative to historical averages.

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

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.

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.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include quarterly distributions, debt service, customary operating expenses, and capital expenditures.

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.

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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 pay distributions or to fund other short - term working capital requirements.

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.

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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Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

The general partner establishes cash reserves to provide for the proper conduct of our business, including (i) reserves to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters.

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 2022 of $0.50000 per unit, or $196.6 million in the aggregate.

The cash distribution was paid on February 14, 2022, to our unitholders of record at the close of business on January 31, 2022.

In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021.

During the year ended December 31, 2021, we repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million, fulfilling the entire $250.0 million authorized program.

The units were canceled immediately upon receipt.

The cash distribution was paid on February 13, 2023, to our unitholders of record at the close of business on February 1, 2023.

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.

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.

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.

The units were canceled immediately upon receipt.

As of December 31, 2022, we had an authorized amount of $762.4 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 quarterly distributions with expected cash inflows and projected debt-service requirements.

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.

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As of December 31, 2022, we had a $3.4 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 4.000% Senior Notes due 2022 of $502.1 million being classified as short-term debt on the consolidated balance sheet as of December 31, 2021.

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.

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Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure.

Capital expenditures includes maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets;

and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.

Capital expenditures include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.

Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made.

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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 during 2019 included AMA and the 30% interest in Red Bluff Express.

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

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.

Capital expenditures decreased by $765.7 million for the year ended December 31, 2020, primarily due to decreases of (i) $362.5 million at the DJ Basin complex primarily related to the completion of Latham Trains I and II that commenced operations in November 2019 and February 2020, respectively, as well as decreases in pipeline, well connection, and compression projects, (ii) $186.8 million at the West Texas complex primarily attributable to the completion of Mentone Train II that commenced operations in March 2019 and decreases in pipeline and well connection projects, (iii) $107.5 million at the DBM oil system primarily related to the completion of the Loving ROTF Train III that commenced operations in January 2020 and decreases in pipeline and well connection projects, and (iv) $90.4 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering 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 increased for the year ended December 31, 2020, primarily due to (i) higher cash operating income, (ii) lower cash paid to settle interest-rate swap agreements, and (iii) higher distributions from equity-investment earnings.

These increases were offset partially by higher interest expense.

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

Investing activities .

Net cash used in investing activities for the year ended December 31, 2021, included the following:

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

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

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

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

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

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

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

Net cash used in investing activities for the year ended December 31, 2021, primarily included the following:

• $313.7 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;

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

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

Net cash used in investing activities for the year ended December 31, 2019, included the following:

• $2.0 billion of cash paid for the acquisition of AMA;

• $1.2 billion of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM water systems;

• $128.4 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for construction activities;

• $92.5 million of cash paid for the acquisition of our interest in Red Bluff Express;

• $30.3 million of distributions received from equity investments in excess of cumulative earnings.

Financing activities .

Net cash used in financing activities for the year ended December 31, 2021, included the following:

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

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

• $735.8 million of distributions paid to WES unitholders;

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

• $487.6 million of unit repurchases;

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

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

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

• $2.2 million of increases in outstanding checks.

Net cash used in financing activities for the year ended December 31, 2021, 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;

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

• $6.5 million of finance lease payments;

• $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;

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• $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.

Net cash provided by financing activities for the year ended December 31, 2019, included the following:

• $3.0 billion of borrowings under the Term loan facility, net of issuance costs, which were used to fund the acquisition of AMA, to repay the APCWH Note Payable, and to repay amounts outstanding under the RCF;

• $1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including the funding of capital expenditures;

• $458.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

• $11.0 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;

• $7.4 million of capital contributions from Anadarko related to the above-market component of swap agreements;

• $1.0 billion of repayments of outstanding borrowings under the RCF;

• $969.1 million of distributions paid to WES unitholders;

• $439.6 million of repayments of the total outstanding balance under the APCWH Note Payable;

• $118.2 million of distributions paid to the noncontrolling interest owners of WES Operating;

• $28.0 million of repayments of the total outstanding balance under the WGP RCF, which matured in March 2019;

• $9.7 million of distributions paid to the noncontrolling interest owner of Chipeta.

Debt and credit facilities.

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

In August 2021 and December 2021, Standard and Poor’s (“S&P”) and Fitch Ratings, respectively, upgraded WES Operating’s long-term debt from “BB” to “BB+.” In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” As a result of these upgrades, annualized borrowing costs will decrease by $23.6 million.

During the third quarter of 2021, WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer.

During the first quarter of 2021, WES Operating redeemed the total principal amount outstanding of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture.

During the year ended December 31, 2021, losses of $24.9 million were recognized for the retirement of these notes.

As of December 31, 2021, the 4.000% Senior Notes due 2022 were classified as short-term debt on the consolidated balance sheet.

At December 31, 2021, WES Operating was in compliance with all covenants under the relevant governing indentures.

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.

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Revolving credit facility.

WES Operating’s $2.0 billion senior unsecured revolving credit facility is expandable to a maximum of $2.5 billion, and matures in February 2025 for each extending lender.

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.

As of December 31, 2021, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF.

As of December 31, 2021, the interest rate on any outstanding RCF borrowings was 1.60% and the facility - fee rate was 0.25%.

The RCF bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, 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) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating.

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.

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

At December 31, 2021, WES Operating was in compliance with all covenants under the RCF.

Finance lease liabilities.

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Operating leases.

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

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

As of December 31, 2022, we have future operating-lease payments of $10.5 million in 2023 and a total of $41.7 million in years thereafter.

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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.

Credit risk .

We bear credit risk through exposure to non - payment or non - performance by our counterparties, including Occidental, financial institutions, customers, and other parties.

Generally, non - payment or non - performance results from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas - imbalance agreements.

We examine and monitor the creditworthiness of customers and may establish credit limits for customers.

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

the contribution agreements;

or the Services Agreement.

ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

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Net income (loss) attributable to WES $ 1,217,103 $ 916,292 $ 527,012

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

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

24,899 18,765 10,830

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Income taxes 7 9 —

Interest expense — — 245

Net income (loss) attributable to WES Operating $ 1,244,620 $ 937,987 $ 541,377

_________________________________________________________________________________________

(1) Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES.

A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2021, 2020, and 2019.

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.

(1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.

A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented.

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

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Income taxes 7 9 —

Interest expense — — 245

Debt related amortization and other items, net — — (20)

WES Operating net cash provided by operating activities $ 1,694,133 $ 1,765,379 $ 1,640,651

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Unit repurchases 487,590 217,465 32,535

Registration expenses related to the issuance of WES common units — — 855

WGP RCF repayments — — 28,000

Other 9,326 4,336 —

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See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating LTIP.

Concurrent with the Merger closing, we assumed the Western Gas Partners, LP 2017 Long-Term Incentive Plan.

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

CRITICAL ACCOUNTING ESTIMATES

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For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Service revenues – fee based.

Certain of our midstream services contracts have minimum-volume-commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost of service.

These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract.

Annual adjustments are made to the cost-of-service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate based on the total expected variable consideration under the contract.

The cost-of-service rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses.

If management determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal.

See Revenue and cost of product in Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of property, plant, and equipment and other intangible assets.

Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired.

Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially recorded at Anadarko’s historic carrying value.

Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control;

therefore, the assets acquired were initially recorded at Anadarko’s historic carrying value.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.

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If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense.

We recognized long-lived asset and other impairments of $30.5 million (which includes an other-than-temporary impairment expense of an equity investment), $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), and $6.3 million for the years ended December 31, 2021, 2020, and 2019, respectively.

See Note 9—Property, Plant, and Equipment and Note 10—Goodwill and Other Intangibles 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, 2021, 2020, and 2019.

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.

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, 2022, 2021, and 2020.

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

Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions, and interest-rate swaps.

Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions.

See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis