Western Midstream Partners, LP 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K. The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2022 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental. EXECUTIVE SUMMARY We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural - gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North - central Pennsylvania. As of December 31, 2022, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems (1) 17 2 3 1 Treating facilities 37 3 — — Natural - gas processing plants/trains 25 3 — 3 NGLs pipelines 2 — — 5 Natural - gas pipelines 6 — — 1 Crude - oil pipelines 3 1 — 3 _________________________________________________________________________________________ (1) Includes the DBM water systems. Significant financial and operational events during the year ended December 31, 2022, included the following: • WES Operating redeemed the $502.2 million total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value. • We repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased from Occidental, for an aggregate purchase price of $487.6 million. In November 2022, the Board authorized an increase in the repurchase program from $1.0 billion to $1.25 billion. • 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. 63 Table of Contents • 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 $2.2 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: Year Ended December 31, 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,470 1,256 17 % 1,297 (3) % DJ Basin 1,331 1,369 (3) % 1,305 5 % Equity investments 483 463 4 % 445 4 % Other 1,082 1,215 (11) % 1,386 (12) % Total throughput for natural - gas assets 4,366 4,303 1 % 4,433 (3) % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 198 183 8 % 189 (3) % DJ Basin 82 90 (9) % 101 (11) % Equity investments 373 366 2 % 381 (4) % Other 37 33 12 % 41 (20) % Total throughput for crude - oil and NGLs assets 690 672 3 % 712 (6) % Throughput for produced-water assets (MBbls/d) Delaware Basin 853 717 19 % 712 1 % Total throughput for produced - water assets 853 717 19 % 712 1 % 64 Table of Contents OUR OPERATIONS Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems, and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather and dispose of produced water. We operate in Texas, New Mexico, Colorado, Utah, 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, 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 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 certain of our 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 alter drilling or production schedules in certain areas, which could cause variability in the volumes of hydrocarbons available to our systems. We also bear limited commodity-price risk through the settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K. 65 Table of Contents HOW WE EVALUATE OUR OPERATIONS Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7). Throughput . Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities. Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors. Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services. General and administrative expenses . To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods 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 Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Commodity purchase and sale agreements . Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership. Accordingly, we no longer recognize service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC. Year-over-year variances for the year ended December 31, 2021, include the following impacts related to this change (i) decrease of $45.9 million in Service revenues – fee based, (ii) decrease of $21.2 million in Product sales, and (iii) decrease of $67.1 million in Cost of product expense. These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see Reconciliation of Non-GAAP Financial Measures within this Item 7). See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 66 Table of Contents Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. In addition, certain of our natural-gas processing agreements provide our producer customers with the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows. See Risk Factors under Part I, Item 1A of this Form 10-K. Weather-related impacts. In February 2021, the U.S. experienced winter storm Uri, bringing extreme cold temperatures, ice, and snow to the central U.S., including Texas, and in March 2021, Colorado experienced a historic blizzard. Winter storm Uri adversely affected our volumes for approximately ten days and the blizzard in Colorado likewise disrupted our assets in that state. We estimate the impact of these weather events reduced our net income and Adjusted EBITDA (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2) for the year ended December 31, 2021, by approximately $30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities. Impairments. We recognized long-lived asset and other impairments of $20.6 million, $30.5 million, and $203.9 million for the years ended December 31, 2022, 2021, and 2020, respectively. During the year ended December 31, 2020, we also recognized a goodwill impairment of $441.0 million, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero. For a description of impairments recorded, see Note 9—Property, Plant, and Equipment , Note 7—Equity Investments , and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. General and administrative expenses. In December 2019, we executed several agreements with Occidental that enabled us to operate as a standalone business. As a result, beginning in 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity. Acquisitions and divestitures. In 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. During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed. We received total proceeds of $8.0 million, $7.0 million in the fourth quarter of 2020 and $1.0 million when the sale closed in the second quarter of 2021, resulting in a net gain on sale of $5.4 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 67 Table of Contents RESULTS OF OPERATIONS OPERATING RESULTS The following tables and discussion present a summary of our results of operations: Year Ended December 31, thousands 2022 2021 2020 Total revenues and other (1) $ 3,251,721 $ 2,877,155 $ 2,772,592 Equity income, net – related parties 183,483 204,645 226,750 Total operating expenses (1) 1,950,992 1,745,573 2,129,063 Gain (loss) on divestiture and other, net 103,676 44 8,634 Operating income (loss) 1,587,888 1,336,271 878,913 Interest income – Anadarko note receivable — — 11,736 Interest expense (333,939) (376,512) (380,058) Gain (loss) on early extinguishment of debt 91 (24,944) 11,234 Other income (expense), net 1,603 (623) 1,025 Income (loss) before income taxes 1,255,643 934,192 522,850 Income tax expense (benefit) 4,187 (9,807) 5,998 Net income (loss) 1,251,456 943,999 516,852 Net income (loss) attributable to noncontrolling interests 34,353 27,707 (10,160) Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,217,103 $ 916,292 $ 527,012 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, and NGLs to related parties. Total operating expenses includes amounts charged by related parties for services received. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (2) For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7. For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2022” refer to the comparison of the year ended December 31, 2022, to the year ended December 31, 2021, and any increases or decreases “for the year ended December 31, 2021” refer to the comparison of the year ended December 31, 2021, to the year ended December 31, 2020. 68 Table of Contents Throughput Year Ended December 31, 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 409 466 (12) % 543 (14) % Processing 3,474 3,374 3 % 3,445 (2) % Equity investments (1) 483 463 4 % 445 4 % Total throughput 4,366 4,303 1 % 4,433 (3) % Throughput attributable to noncontrolling interests (2) 156 155 1 % 159 (3) % Total throughput attributable to WES for natural - gas assets 4,210 4,148 1 % 4,274 (3) % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 317 306 4 % 331 (8) % Equity investments (1) 373 366 2 % 381 (4) % Total throughput 690 672 3 % 712 (6) % Throughput attributable to noncontrolling interests (2) 14 13 8 % 14 (7) % Total throughput attributable to WES for crude - oil and NGLs assets 676 659 3 % 698 (6) % Throughput for produced-water assets (MBbls/d) Gathering and disposal 853 717 19 % 712 1 % Throughput attributable to noncontrolling interests (2) 17 14 21 % 14 — % Total throughput attributable to WES for produced - water assets 836 703 19 % 698 1 % _________________________________________________________________________________________ (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 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. 69 Table of Contents 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. Crude-oil and NGLs assets Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes at the DBM oil system resulting from increased production in the area, partially offset by lower volumes at the DJ Basin oil system resulting from production declines in the area. Gathering, treating, and transportation throughput decreased by 25 MBbls/d for the year ended December 31, 2021, primarily due to (i) lower volumes at the DJ Basin and Springfield oil systems resulting from production declines in the areas and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri. Equity - investment throughput increased by 7 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes on FRP resulting from increased pipeline commitments. This increase was offset partially by (i) lower volumes on the Cactus II pipeline, which was sold to two third parties in the fourth quarter of 2022, and (ii) decreased volumes on the Whitethorn pipeline. Equity - investment throughput decreased by 15 MBbls/d for the year ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline. 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. 70 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Service revenues – fee based $ 2,602,053 $ 2,462,835 6 % $ 2,584,323 (5) % Service revenues – product based 249,692 122,584 104 % 48,369 153 % Total service revenues $ 2,851,745 $ 2,585,419 10 % $ 2,632,692 (2) % 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 – 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. 71 Table of Contents Product Sales Year Ended December 31, thousands except percentages and per-unit amounts 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Natural - gas sales $ 129,187 $ 83,102 55 % $ 30,527 172 % NGLs sales 269,836 207,845 30 % 108,032 92 % Total Product sales $ 399,023 $ 290,947 37 % $ 138,559 110 % Per - unit gross average sales price: Natural gas (per Mcf) $ 5.66 $ 4.31 31 % $ 1.45 197 % NGLs (per Bbl) 40.51 33.69 20 % 13.14 156 % Natural-gas sales Natural - gas sales increased by $46.1 million for the year ended December 31, 2022, primarily due to increases of $45.7 million, $7.1 million, and $4.1 million at the West Texas complex, MGR assets, and Granger complex, respectively, attributable to increased average prices and volumes sold. These increases were offset partially by a decrease of $14.1 million at the DJ Basin complex due to decreased volumes sold, partially offset by an increase in average prices. Natural - gas sales increased by $52.6 million for the year ended December 31, 2021, primarily due to increases of (i) $49.0 million at the West Texas complex attributable to an increase in average prices, (ii) $9.6 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes sold, and (iii) $1.8 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). These increases were offset partially by decreases of $5.6 million at the DJ Basin complex and $4.9 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices. NGLs sales 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). 72 Table of Contents Equity Income, Net – Related Parties Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) 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. Cost of Product and Operation and Maintenance Expenses Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Residue purchases $ 173,104 $ 146,709 18 % $ 65,193 125 % NGLs purchases 320,739 187,231 71 % 131,964 42 % Other (72,943) (11,655) NM (9,069) 29 % Cost of product 420,900 322,285 31 % 188,088 71 % Operation and maintenance 654,566 581,300 13 % 580,874 — % Total Cost of product and Operation and maintenance expenses $ 1,075,466 $ 903,585 19 % $ 768,962 18 % _________________________________________________________________________________________ NM — Not meaningful Residue purchases Residue purchases increased by $26.4 million for the year ended December 31, 2022, primarily due to increases of (i) $15.3 million at the West Texas complex attributable to increased volumes purchased and average prices, as well as changes in contract mix during 2022, (ii) $10.1 million at the Chipeta complex due to increased volumes purchased and average prices, and (iii) $6.1 million and $4.7 million at the MGR assets and the Granger complex, respectively, primarily attributable to increased average prices. These increases were offset partially by a decrease of $9.5 million at the DJ Basin complex primarily due to a change in contract mix during the second quarter of 2022. Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.7 million at the West Texas complex, $6.7 million at the Chipeta complex, and $6.3 million at the Hilight system attributable to increases in average prices and (ii) $9.2 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $5.2 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). 73 Table of Contents NGLs purchases NGLs purchases increased by $133.5 million for the year ended December 31, 2022, primarily due to increases of (i) $76.7 million at the West Texas complex due to increased volumes purchased and average prices, as well as a change in contract mix during the second quarter of 2022, (ii) $58.5 million at the DJ Basin complex attributable to increased average prices and a change in contract mix during the second quarter of 2022, and (iii) $4.2 million at the DBM water systems due to increased average prices and volumes purchased. These increases were offset partially by a decrease of $4.6 million at the Brasada complex due to a contract expiration in the third quarter of 2022. NGLs purchases increased by $55.3 million for the year ended December 31, 2021, primarily due to increases of (i) $53.3 million at the West Texas complex, $13.7 million at the Chipeta complex, and $8.2 million at the Granger complex attributable to increases in average prices, (ii) $35.2 million at the DJ Basin complex attributable to an increase in average prices and volumes purchased, and (iii) $4.1 million at the Brasada complex attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $61.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). Other items 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 $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. 74 Table of Contents Other Operating Expenses Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) General and administrative $ 194,017 $ 195,549 (1) % $ 155,769 26 % Property and other taxes 78,559 64,267 22 % 68,340 (6) % Depreciation and amortization 582,365 551,629 6 % 491,086 12 % Long - lived asset and other impairments 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. 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. 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. 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. 75 Table of Contents Long - lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex. Long-lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects For further information on our equity investments and other-than-temporary impairments, see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For further information on Long - lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Interest Income – Anadarko Note Receivable and Interest Expense Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Interest income – Anadarko note receivable $ — $ — — % $ 11,736 (100) % Long - term and short - term debt $ (326,949) $ (366,570) (11) % $ (369,815) (1) % 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) % Interest expense $ (333,939) $ (376,512) (11) % $ (380,058) (1) % Interest income Interest income - Anadarko note receivable decreased by $11.7 million for the year ended December 31, 2021, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Interest expense Interest expense decreased by $42.6 million for the year ended December 31, 2022, primarily due to decreases of (i) $21.3 million primarily due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 and 5.375% Senior Notes due 2021 during the second quarter of 2022 and first quarter of 2021, respectively, (ii) $16.8 million due to credit-rating related interest rate changes on the 4.050% Senior Notes due 2030 and 5.250% Senior Notes due 2050, (iii) $13.5 million due to credit-rating related interest rate changes and a lower outstanding balance on the 3.100% Senior Notes due 2025, and (iv) $2.7 million due to a lower outstanding balance on the 3.950% Senior Notes due 2025, a portion of which was repaid during the third quarter of 2021. These decreases were offset partially by an increase of $13.6 million due to higher outstanding borrowings and average interest rates under the RCF during 2022. Interest expense decreased by $3.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $21.2 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 during the first quarter of 2021, (ii) $5.7 million due to lower outstanding balances on the 4.000% Senior Notes due 2022, Floating Rate Notes due 2023, 3.950% Senior Notes due 2025, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021, and (iii) $3.6 million due to lower outstanding borrowings under the RCF in 2021. These decreases were offset partially by (i) an increase of $26.4 million in additional interest incurred from higher effective interest rates resulting from credit - rating downgrades on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and (ii) a decrease of $1.2 million in capitalized interest due to decreased capital expenditures. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7. 76 Table of Contents Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Income (loss) before income taxes $ 1,255,643 $ 934,192 34 % $ 522,850 79 % Income tax expense (benefit) 4,187 (9,807) (143) % 5,998 NM Effective tax rate — % NM 1 % We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. For the 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. RECONCILIATION OF NON-GAAP FINANCIAL MEASURES Adjusted gross margin. We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity - related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product. We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties. The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are reimbursed by certain customers (recorded as revenue with an offset recorded as Operation and maintenance expense). Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following: • our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis; • the ability of our assets to generate cash flow to make distributions; and • the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. Free cash flow. We define “Free cash flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free cash flow an appropriate metric for assessing capital discipline, cost efficiency, and balance - sheet strength. Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period. Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes. 77 Table of Contents Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted gross margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA. The GAAP measure that is most directly comparable to Free cash flow is net cash provided by operating activities. Our non - GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted gross margin, Adjusted EBITDA, and Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures. Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results. The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free cash flow: Year Ended December 31, thousands 2022 2021 2020 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 3,251,721 $ 2,877,155 $ 2,772,592 Less: Cost of product 420,900 322,285 188,088 Depreciation and amortization 582,365 551,629 491,086 Gross margin 2,248,456 2,003,241 2,093,418 Add: Distributions from equity investments 250,050 254,901 278,797 Depreciation and amortization 582,365 551,629 491,086 Less: Reimbursed electricity-related charges recorded as revenues 81,764 74,405 79,261 Adjusted gross margin attributable to noncontrolling interests (1) 73,632 67,850 65,835 Adjusted gross margin $ 2,925,475 $ 2,667,516 $ 2,718,205 _________________________________________________________________________________________ (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. 78 Table of Contents 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 . Year Ended December 31, thousands except per-unit amounts 2022 2021 2020 Gross margin 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 $ 2,031,600 $ 1,882,726 $ 1,820,926 Adjusted gross margin for crude - oil and NGLs assets 607,769 547,134 647,390 Adjusted gross margin for produced - water assets 286,106 237,656 249,889 Per - Mcf Adjusted gross margin for natural - gas assets (3) 1.32 1.24 1.16 Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (3) 2.46 2.28 2.54 Per - Bbl Adjusted gross margin for produced - water assets (3) 0.94 0.93 0.98 _________________________________________________________________________________________ (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. 79 Table of Contents Year Ended December 31, thousands 2022 2021 2020 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,251,456 $ 943,999 $ 516,852 Add: Distributions from equity investments 250,050 254,901 278,797 Non - cash equity - based compensation expense 27,783 27,676 22,462 Interest expense 333,939 376,512 380,058 Income tax expense 4,187 4,403 10,278 Depreciation and amortization 582,365 551,629 491,086 Impairments (1) 20,585 30,543 644,906 Other expense 555 1,468 1,953 Less: Gain (loss) on divestiture and other, net 103,676 44 8,634 Gain (loss) on early extinguishment of debt 91 (24,944) 11,234 Equity income, net – related parties 183,483 204,645 226,750 Interest income – Anadarko note receivable — — 11,736 Other income 1,648 585 2,785 Income tax benefit — 14,210 4,280 Adjusted EBITDA attributable to noncontrolling interests (2) 54,049 49,901 50,607 Adjusted EBITDA $ 2,127,973 $ 1,946,690 $ 2,030,366 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Interest (income) expense, net 333,939 376,512 368,322 Accretion and amortization of long - term obligations, net (7,142) (7,635) (8,654) Current income tax expense (benefit) 2,188 (37) 2,702 Other (income) expense, net (1,603) 623 (1,025) Cash paid to settle interest - rate swaps — — 25,621 Distributions from equity investments in excess of cumulative earnings – related parties 63,897 41,385 32,160 Changes in assets and liabilities: Accounts receivable, net 116,296 (16,366) 193,688 Accounts and imbalance payables and accrued liabilities, net 7,812 (114,887) (144,437) Other items, net (34,791) (49,856) (24,822) Adjusted EBITDA attributable to noncontrolling interests (2) (54,049) (49,901) (50,607) Adjusted EBITDA $ 2,127,973 $ 1,946,690 $ 2,030,366 Cash flow information Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Net cash used in investing activities (218,237) (257,538) (448,254) Net cash provided by (used in) financing activities (1,398,532) (1,752,237) (844,204) _________________________________________________________________________________________ (1) Includes goodwill impairment for the year ended December 31, 2020. See Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (2) For all periods presented, includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 80 Table of Contents Year Ended December 31, thousands 2022 2021 2020 Reconciliation of Net cash provided by operating activities to Free cash flow Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Less: Capital expenditures 487,228 313,674 423,602 Contributions to equity investments – related parties 9,632 4,435 19,388 Add: Distributions from equity investments in excess of cumulative earnings – related parties 63,897 41,385 32,160 Free cash flow $ 1,268,463 $ 1,490,128 $ 1,226,588 Cash flow information Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Net cash used in investing activities (218,237) (257,538) (448,254) 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. 81 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) 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 % _________________________________________________________________________________________ (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. 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. 82 Table of Contents Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 for the year ended December 31, 2022, primarily due to strong plant performance and contract mix leading to increased product recoveries, coupled with higher commodity prices and increased throughput at the West Texas complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets. Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 for the year ended December 31, 2021, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex and (ii) a higher cost - of - service rate effective January 1, 2021, at the Springfield system. These increases were offset partially by decreased throughput on certain fee-based contracts at the DJ Basin complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.18 for the year ended December 31, 2022, primarily due to (i) increased throughput and increased deficiency fee revenues at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021 at the DJ Basin oil system, and (iii) an increase in distributions from Cactus II. These increases were offset partially by (i) lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021 at the Springfield system, (ii) a decrease in distributions from Saddlehorn and Whitethorn LLC, and (iii) increased throughput on FRP, which has a lower - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets decreased by $0.26 for the year ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system and (ii) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets. These decreases were offset partially by a higher cost - of - service rate effective January 1, 2021, at the Springfield system. Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021. Adjusted EBITDA. Adjusted EBITDA increased by $181.3 million for the year ended December 31, 2022, primarily due to a $374.6 million increase in total revenues and other. This amount was offset partially by (i) a $98.4 million increase in cost of product expense (net of lower of cost or market inventory adjustments), (ii) a $73.3 million increase in operation and maintenance expenses, (iii) a $14.3 million increase in property taxes, and (iv) a $4.9 million decrease in distributions from equity investments. Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments. These amounts were offset partially by (i) a $104.6 million increase in total revenues and other and (ii) a $4.1 million decrease in property taxes. The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). Free cash flow. Free cash flow decreased by $221.7 million for the year ended December 31, 2022, primarily due to (i) a $173.6 million increase in capital expenditures, (ii) a $65.4 million decrease in net cash provided by operating activities, and (iii) a $5.2 million increase in contributions to equity investments. These amounts were offset partially by a $22.5 million increase in distributions from equity investments in excess of cumulative earnings. Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings. See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. 83 Table of Contents GENERAL TRENDS AND OUTLOOK We expect our business to be affected by the below - described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results. Impact of crude-oil, natural-gas, and NGLs prices. Crude - oil, natural - gas, and NGLs prices can fluctuate significantly, and have done so over time. Commodity - price fluctuations affect the level of our customers’ activities and our customers’ allocations of capital within their own asset portfolios. 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. In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions. From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute. Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are becoming more numerous, more stringent, and more complex. These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells. In addition, in certain areas in which we operate, public protests of oil and gas operations are not uncommon. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets. Impact of inflation and supply-chain disruptions. Although inflation in the United States has been relatively low in recent years, the U.S. economy currently is experiencing significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine. More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for labor, materials, fuel, and services, which has increased our operating costs and capital expenditures. 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. 84 Table of Contents Impact of interest rates. Overall, short- and long-term interest rates increased during 2021 and have continued to increase during 2022, resulting in increased interest expense on RCF borrowings and the Floating - Rate Senior Notes. 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. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics. Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies. However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited. LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity as of December 31, 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. We believe that cash flows generated from these sources will be sufficient to satisfy our short - term working capital requirements and long - term capital - expenditure and debt-service requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board on a quarterly basis. We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions. However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to fund equity or other short - term working capital requirements. Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) within 55 days following each quarter’s end. Our cash flow and resulting ability to make cash distributions are dependent on our ability to generate cash flow from operations. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter. The general partner establishes cash reserves to provide for the proper conduct of our business, including (i) to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. 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 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. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the year ended December 31, 2022, we repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased 85 Table of Contents 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 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. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K. Working capital . Working capital is an indication of liquidity and potential needs for short - term funding. Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and other capital activities. As of December 31, 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 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. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels. Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2022 2021 2020 Acquisitions $ 40,127 $ — $ — Capital expenditures (1) 487,228 313,674 423,602 Capital incurred (1) 534,342 324,150 307,644 _________________________________________________________________________________________ (1) For the years ended December 31, 2022, 2021, and 2020, included $5.6 million, $3.6 million, and $4.8 million, respectively, of capitalized interest. Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures within this Item 7). Capital expenditures increased by $173.6 million for the year ended December 31, 2022, primarily due to increases of (i) $119.9 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III, and pipeline projects, (ii) $31.8 million at the DBM water systems due to construction of additional water - disposal wells and facilities and pipeline projects, and (iii) $17.3 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects. These increases were offset partially by a decrease of $8.9 million at the DJ Basin oil system, primarily related to a decrease in pipeline projects. 86 Table of Contents 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. Historical cash flow . The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities: Year Ended December 31, thousands 2022 2021 2020 Net cash provided by (used in): Operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Investing activities (218,237) (257,538) (448,254) Financing activities (1,398,532) (1,752,237) (844,204) Net increase (decrease) in cash and cash equivalents $ 84,657 $ (242,923) $ 344,960 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. 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, 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; and • $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; 87 Table of Contents • $41.4 million of distributions received from equity investments in excess of cumulative earnings; • $11.1 million of decreases to materials and supplies inventory; and • $8.0 million related to the sale of the Bison treating facility. Net cash used in investing activities for the year ended December 31, 2020, included the following: • $423.6 million of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM water systems, and DBM oil system; • $57.8 million of increases to materials and supplies inventory; • $19.4 million of capital contributions primarily paid to Cactus II and FRP for construction activities; • $32.2 million of distributions received from equity investments in excess of cumulative earnings; and • $20.3 million in proceeds primarily from the sale of Fort Union. Financing activities . 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; and • $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; • $480.0 million of repayments of outstanding borrowings under the RCF; • $431.1 million to redeem the total principal amount outstanding of WES Operating’s 5.375% Senior Notes due 2021; • $217.5 million of unit repurchases; 88 Table of Contents • $21.6 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020; • $15.0 million of distributions paid to the noncontrolling interest owner of WES Operating; • $9.1 million of distributions paid to the noncontrolling interest owner of Chipeta; • $480.0 million of borrowings under the RCF, which were used for general partnership purposes and to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer; and • $8.5 million of contributions from related parties. Net cash used in financing activities for the year ended December 31, 2020, included the following: • $3.0 billion of repayments of outstanding borrowings under the Term loan facility; • $600.0 million of repayments of outstanding borrowings under the RCF; • $695.8 million of distributions paid to WES unitholders; • $203.9 million to purchase and retire portions of WES Operating’s 5.375% Senior Notes due 2021, 4.000% Senior Notes due 2022, and Floating-Rate Senior Notes via open-market repurchases; • $32.5 million of unit repurchases; • $15.4 million of distributions paid to the noncontrolling interest owner of WES Operating; • $14.2 million of finance lease payments; • $8.6 million of distributions paid to the noncontrolling interest owner of Chipeta; • $3.5 billion of net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued in January 2020, which were used to repay the $3.0 billion outstanding borrowings under the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes; • $220.0 million of borrowings under the RCF, which were used for general partnership purposes; • $20.7 million of increases in outstanding checks due mostly to ad valorem tax payments made at the end of the year; and • $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. 89 Table of Contents Debt and credit facilities. As of December 31, 2022, the carrying value of outstanding debt was $6.8 billion and we have estimated future interest and RCF fee payments totaling $325.0 million in 2023. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. WES Operating Senior Notes . In mid - January 2020, WES Operating issued the Fixed - Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and the Floating - Rate Senior Notes due 2023. Including the effects of the issuance prices, underwriting discounts, and interest - rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 3.790%, 4.671%, and 5.869%, respectively, at December 31, 2022. The interest rate on the Floating - Rate Senior Notes was 5.04% at December 31, 2022. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-” and in March 2022, Moody’s upgraded WES Operating’s long-term debt from “Ba2” to “Ba1.” As a result of these upgrades, annualized borrowing costs decreased by $15.7 million. During the second quarter of 2022, WES Operating (i) redeemed the total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value and (ii) purchased and retired $1.4 million of the 3.100% Senior Notes due 2025 via open-market repurchases. As of December 31, 2022, the Floating-Rate Senior Notes were classified as short-term debt on the consolidated balance sheet, and in January 2023, WES Operating redeemed the total principal amount outstanding at par value with cash on hand. As of December 31, 2022, WES Operating was in compliance with all covenants under the relevant governing indentures. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors. The amounts involved may be material. Revolving credit facility. In June 2022, WES Operating entered into an amendment to its $2.0 billion RCF, which is expandable to a maximum of $2.5 billion, to, among other things, (i) extend the maturity date applicable to the loans and commitments of certain lenders totaling $1.6 billion to February 2026, (ii) provide for the ability of WES Operating to extend the maturity date by one year on up to two additional occasions, (iii) provide that loans under the RCF with a fixed interest rate for a specified period bear interest based on SOFR instead of LIBOR, and (iv) include an additional level of pricing if WES Operating’s senior unsecured debt rating is less than or equal to BB/Ba2/BB (S&P / Moody’s Investors Service / Fitch Ratings). The non - extending lender’s commitments mature in February 2025 and represent $400.0 million out of $2.0 billion of total commitments from all lenders. The RCF bears interest at an Adjusted Term SOFR (as defined in the RCF amendment), plus applicable margins ranging from 1.00% to 1.70%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Adjusted Term SOFR for a one-month tenor in effect on such day plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.70%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.300% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating. As of December 31, 2022, there were $375.0 million of outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $1.6 billion of available borrowing capacity under the RCF. As of December 31, 2022, the interest rate on any outstanding RCF borrowings was 5.92% and the facility - fee rate was 0.25%. As of December 31, 2022, the outstanding borrowings under the RCF were classified as long-term debt on the consolidated balance sheet and WES Operating was in compliance with all covenants under the RCF. The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related - party transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most - recent four - consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270 - day period immediately following certain acquisitions. As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited. 90 Table of Contents Finance lease liabilities. During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles. Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification. As a result, these leases were classified as operating leases. As of December 31, 2022, we have future finance-lease payments of $2.7 million in 2023 and a total of $5.3 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties, plant, and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2022, we expect to incur asset retirement costs of $10.5 million in 2023 and a total of $290.0 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Operating leases. We have 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. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Pipeline commitments. In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline. As of December 31, 2022, we have estimated future minimum-volume-commitment fees of $3.7 million in 2023 and a total of $7.4 million in years thereafter. Offload commitments. During the year ended December 31, 2022, we entered into offload agreements with third parties providing firm-processing capacity through 2025. As of December 31, 2022, we have future minimum payments under offload agreements totaling $16.8 million in 2023 and a total of $10.5 million in years thereafter. Credit risk . We bear credit risk through exposure to non - payment or non - performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non - payment or non - performance results from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance. We expect our exposure to the concentrated risk of non - payment or non - performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental - produced volumes, but also, in some instances, the volumes of other working - interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements. 91 Table of Contents ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below. Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2022 2021 2020 Net income (loss) attributable to WES $ 1,217,103 $ 916,292 $ 527,012 Limited partner interest in WES Operating not held by WES (1) 24,899 18,765 10,830 General and administrative expenses (2) 2,656 2,932 3,552 Other income (expense), net (45) (11) (17) Income taxes 7 9 — 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 interest in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2022 2021 2020 WES net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 General and administrative expenses (1) 2,656 2,932 3,552 Non - cash equity - based compensation expense (570) 6,912 (7,858) Changes in working capital (9,341) (11,315) 7,556 Other income (expense), net (45) (11) (17) Income taxes 7 9 — WES Operating net cash provided by operating activities $ 1,694,133 $ 1,765,379 $ 1,640,651 WES net cash provided by (used in) financing activities $ (1,398,532) $ (1,752,237) $ (844,204) Distributions to WES unitholders (2) 735,755 533,758 695,834 Distributions to WES from WES Operating (3) (1,219,635) (734,034) (756,112) Increase (decrease) in outstanding checks 103 (68) (35) Unit repurchases 487,590 217,465 32,535 Other 9,326 4,336 — WES Operating net cash provided by (used in) financing activities $ (1,385,393) $ (1,730,780) $ (871,982) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. (2) Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (3) Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 92 Table of Contents Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders in proportion to their share of limited partner interests in WES Operating. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. CRITICAL ACCOUNTING ESTIMATES The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee. For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. The primary assumptions used to estimate undiscounted future net cash flows include long-range customer production forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets. If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to impairment expense. Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. 93 Table of Contents Impairments of equity investments. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. Management assesses its equity investments for impairment whenever events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense. We recognized long-lived asset and other impairments of $20.6 million, $30.5 million, and $203.9 million (all of which include an other-than-temporary impairment expense of an equity investment) for the years ended December 31, 2022, 2021, and 2020, respectively. 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. Fair value. Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. RECENT ACCOUNTING DEVELOPMENTS See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 94 Table of Contents