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, 2021 (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, 2021, 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 24 3 — 5 NGLs pipelines 2 — — 5 Natural - gas pipelines 5 — — 1 Crude - oil pipelines 3 1 — 4 _________________________________________________________________________________________ (1) Includes the DBM water systems. Significant financial and operational events during the year ended December 31, 2021, included the following: • WES Operating redeemed the total principal amount outstanding of $431.1 million of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture. • WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer. • We repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million. • Our fourth - quarter 2021 per - unit distribution of $0.32700 increased $0.004 from the third - quarter 2021 per - unit distribution of $0.32300. • Natural - gas throughput attributable to WES totaled 4,148 MMcf/d for the year ended December 31, 2021, representing a 3% decrease compared to the year ended December 31, 2020. • Crude - oil and NGLs throughput attributable to WES totaled 659 MBbls/d for the year ended December 31, 2021, representing a 6% decrease compared to the year ended December 31, 2020. 64 Table of Contents • Produced - water throughput attributable to WES totaled 703 MBbls/d for the year ended December 31, 2021, representing a 1% increase compared to the year ended December 31, 2020. • Gross margin was $2.0 billion for the year ended December 31, 2021, representing a 4% decrease compared to the year ended December 31, 2020. See Key Performance Metrics within this Item 7. • Adjusted gross margin for natural - gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $1.24 per Mcf for the year ended December 31, 2021, representing a 7% increase compared to the year ended December 31, 2020. • Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $2.28 per Bbl for the year ended December 31, 2021, representing a 10% decrease compared to the year ended December 31, 2020. • Adjusted gross margin for produced - water assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.93 per Bbl for the year ended December 31, 2021, representing a 5% decrease compared to the year ended December 31, 2020. The following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,256 1,297 (3) % 1,226 6 % DJ Basin 1,369 1,305 5 % 1,236 6 % Equity investments 463 445 4 % 398 12 % Other 1,215 1,386 (12) % 1,563 (11) % Total throughput for natural - gas assets 4,303 4,433 (3) % 4,423 — % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 183 189 (3) % 150 26 % DJ Basin 90 101 (11) % 118 (14) % Equity investments 366 381 (4) % 343 11 % Other 33 41 (20) % 52 (21) % Total throughput for crude - oil and NGLs assets 672 712 (6) % 663 7 % Throughput for produced-water assets (MBbls/d) Delaware Basin 717 712 1 % 556 28 % Total throughput for produced - water assets 717 712 1 % 556 28 % 65 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, 2021, our West Texas and DJ Basin assets provided (i) 47% and 35%, respectively, of Total revenues and other, (ii) 33% and 36%, respectively, each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 60% and 29%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets. For the year ended December 31, 2021, 57% of Total revenues and other, 36% 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 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payment, and/or cost-of-service commitments under certain of our contracts. For the year ended December 31, 2021, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements. We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to delay drilling or shut-in production in certain areas, which would reduce the volumes of hydrocarbons available to our systems. We also 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. 66 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, and (iv) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see in Key Performance Metrics within this Item 7). 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, insurance, repair and maintenance, equipment rentals, fleet management, contract services, utility costs, and services provided to us or on our behalf. 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. 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. Year-over-year variances for the year ended December 31, 2020, include the following impacts related to this change (i) decrease of $130.9 million in Service revenues – fee based, (ii) decrease of $29.7 million in Product sales, and (iii) decrease of $160.6 million in Cost of product expense. These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see Key Performance Metrics within this Item 7). See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Gathering and processing agreements. 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. 67 Table of Contents 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 Key Performance Metrics within this Item 2) for the year ended December 31, 2021, by approximately $30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities. Impairments. We recognized long-lived asset and other impairments of $30.5 million, $203.9 million, and $6.3 million for the years ended December 31, 2021, 2020, and 2019, 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. On December 31, 2019, we entered into the December 2019 Agreements, which helped facilitate our ability to operate more independently from Occidental. As a result, beginning in 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Noncontrolling interests. For periods subsequent to Merger completion, our noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating. For periods prior to Merger completion, our noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, and (iv) the Class C units issued by WES Operating to a subsidiary of Anadarko as part of the funding for the acquisition of DBM. Acquisitions and divestitures. In 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. In February 2019, WES Operating acquired AMA from Anadarko. In January 2019, we acquired a 30% interest in Red Bluff Express. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 68 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 2021 2020 2019 Total revenues and other (1) $ 2,877,155 $ 2,772,592 $ 2,746,174 Equity income, net – related parties 204,645 226,750 237,518 Total operating expenses (1) 1,745,573 2,129,063 1,750,943 Gain (loss) on divestiture and other, net 44 8,634 (1,406) Operating income (loss) 1,336,271 878,913 1,231,343 Interest income – Anadarko note receivable — 11,736 16,900 Interest expense (376,512) (380,058) (303,286) Gain (loss) on early extinguishment of debt (24,944) 11,234 — Other income (expense), net (623) 1,025 (123,785) Income (loss) before income taxes 934,192 522,850 821,172 Income tax expense (benefit) (9,807) 5,998 13,472 Net income (loss) 943,999 516,852 807,700 Net income (loss) attributable to noncontrolling interests 27,707 (10,160) 110,459 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 916,292 $ 527,012 $ 697,241 _________________________________________________________________________________________ (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, 2021” refer to the comparison of the year ended December 31, 2021, to the year ended December 31, 2020, and any increases or decreases “for the year ended December 31, 2020” refer to the comparison of the year ended December 31, 2020, to the year ended December 31, 2019. 69 Table of Contents Throughput Year Ended December 31, 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 466 543 (14) % 528 3 % Processing 3,374 3,445 (2) % 3,497 (1) % Equity investments (1) 463 445 4 % 398 12 % Total throughput 4,303 4,433 (3) % 4,423 — % Throughput attributable to noncontrolling interests (2) 155 159 (3) % 175 (9) % Total throughput attributable to WES for natural - gas assets 4,148 4,274 (3) % 4,248 1 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 306 331 (8) % 320 3 % Equity investments (3) 366 381 (4) % 343 11 % Total throughput 672 712 (6) % 663 7 % Throughput attributable to noncontrolling interests (2) 13 14 (7) % 13 8% Total throughput attributable to WES for crude - oil and NGLs assets 659 698 (6) % 650 7 % Throughput for produced-water assets (MBbls/d) Gathering and disposal 717 712 1 % 556 28 % Throughput attributable to noncontrolling interests (2) 14 14 — % 11 27 % Total throughput attributable to WES for produced - water assets 703 698 1 % 545 28 % _________________________________________________________________________________________ (1) Represents the 14.81% share of average Fort Union throughput (until divested in October 2020), 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput. (2) For all periods presented, includes (i) the 2.0% Occidental subsidiary - owned limited partner interest in WES Operating and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests. (3) Represents the 10% share of average White Cliffs throughput; 25% share of average Mont Belvieu JV throughput; 20% share of average TEG, TEP, Whitethorn, and Saddlehorn throughput; 33.33% share of average FRP throughput; and 15% share of average Panola and Cactus II throughput. Natural-gas assets Gathering, treating, and transportation throughput decreased by 77 MMcf/d for the year ended December 31, 2021, primarily due to (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021 and (ii) production declines and the impact of winter storm Uri at the Springfield gas - gathering system. These decreases were offset partially by increased production in areas around the Marcellus Interest systems. Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year ended December 31, 2020, primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison treating facility and Springfield gas-gathering system. 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. 70 Table of Contents Processing throughput decreased by 52 MMcf/d for the year ended December 31, 2020, primarily due to (i) third-party volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 and the plant being held idle during the third and fourth quarters of 2020, (ii) lower throughput at the Chipeta complex due to production declines in the area and a third-party contract that terminated during the fourth quarter of 2019, and (iii) lower throughput at the Red Desert complex due to production declines in the area. These decreases were offset partially by (i) increased production in areas around the West Texas and DJ Basin complexes, (ii) the start-up of Latham Train II at the DJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at the West Texas complex in March 2019. Equity - investment throughput increased by 18 MMcf/d for the year ended December 31, 2021, primarily due to increased volumes on Red Bluff Express and at the Mi Vida plant, partially offset by (i) decreased volumes at the Rendezvous system due to production declines in the area and (ii) decreased volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020. Equity-investment throughput increased by 47 MMcf/d for the year ended December 31, 2020, primarily due to increased volumes on Red Bluff Express resulting from increased production in the area. This increase was offset partially by (i) decreased third-party volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the Rendezvous system due to production declines in the area. Crude-oil and NGLs assets Gathering, treating, and transportation throughput decreased by 25 MBbls/d for the year ended December 31, 2021, primarily due to (i) lower volumes at the DJ Basin and Springfield oil systems resulting from production declines in the areas and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri. Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2020, primarily due to increased throughput at the DBM oil system with the commencement of Loving ROTF Trains III and IV operations during the first and third quarters of 2020, respectively, and increased production, partially offset by lower throughput at the DJ Basin oil system due to production declines in the area. Equity - investment throughput decreased by 15 MBbls/d for the year ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline. Equity-investment throughput increased by 38 MBbls/d for the year ended December 31, 2020, primarily due to (i) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by decreased volumes on the Whitethorn pipeline. Produced-water assets Gathering and disposal throughput increased by 5 MBbls/d for the year ended December 31, 2021, due to increased volumes at the DBM water systems resulting from (i) higher production in the area, primarily during the second half of 2021, and (ii) new third-party connections brought online during the fourth quarter of 2021. These increases were offset partially by the impact of winter storm Uri. Gathering and disposal throughput increased by 156 MBbls/d for the year ended December 31, 2020, due to increased throughput at the DBM water systems resulting from additional (i) production, (ii) water-disposal facilities, and (iii) offload connections that increased capacity of the systems. 71 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Service revenues – fee based $ 2,462,835 $ 2,584,323 (5) % $ 2,388,191 8 % Service revenues – product based 122,584 48,369 153 % 70,127 (31) % Total service revenues $ 2,585,419 $ 2,632,692 (2) % $ 2,458,318 7 % Service revenues – fee based Service revenues – fee based decreased by $121.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $45.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $36.4 million at the DBM oil system due to decreased throughput, including the impact of winter storm Uri, and lower lease revenue under the operating and maintenance agreement with Occidental, (iii) $23.4 million at the DJ Basin oil system due to an annual cost-of-service rate adjustment made during the fourth quarter of 2021 and decreased throughput, partially offset by a higher average gathering fee, (iv) $19.0 million at the DJ Basin complex due to decreased throughput on certain fee-based contracts, (v) $17.0 million at the Bison treating facility due to the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020, decreased throughput, and the sale of the facility to a third party during the second quarter of 2021, and (vi) $14.3 million at the DBM water systems due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021, partially offset by increased throughput. These decreases were offset partially by increases of (i) $26.6 million at the West Texas complex due to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, partially offset by decreased throughput, including the impact of winter storm Uri, and (ii) $13.1 million at the Springfield system due to cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021. Service revenues – fee based increased by $196.1 million for the year ended December 31, 2020, primarily due to increases of (i) $98.1 million at the West Texas complex and $97.9 million at the DJ Basin complex from increased throughput, (ii) $63.6 million at the DBM oil system from increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, (iii) $59.3 million at the DBM water systems from increased throughput, and (iv) $21.4 million at the Springfield system due to annual cost-of-service rate adjustments that increased revenue in the fourth quarter of 2020 and decreased revenue in the fourth quarter of 2019, partially offset by decreased volumes. These increases were offset partially by a decrease of $130.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). Service revenues – product based Service revenues – product based increased by $74.2 million for the year ended December 31, 2021, primarily due to increases of (i) $22.2 million at the West Texas complex due to an increase in electricity - related fees charged to customers during winter storm Uri, (ii) $20.5 million at the DJ Basin complex due to increased third - party volumes and average prices, and (iii) $8.9 million at the Granger complex, $8.5 million at the Hilight system, $6.9 million at the Chipeta complex, and $5.3 million at the MGR assets due to increased prices. Service revenues – product based decreased by $21.8 million for the year ended December 31, 2020, primarily due to (i) decreased third-party volumes at the DJ Basin complex and MGR assets and (ii) decreased pricing across several systems. 72 Table of Contents Product Sales Year Ended December 31, thousands except percentages and per-unit amounts 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Natural - gas sales $ 83,102 $ 30,527 172 % $ 66,557 (54) % NGLs sales 207,845 108,032 92 % 219,831 (51) % Total Product sales $ 290,947 $ 138,559 110 % $ 286,388 (52) % Per - unit gross average sales price: Natural gas (per Mcf) $ 4.31 $ 1.45 197 % $ 1.65 (12) % NGLs (per Bbl) 33.69 13.14 156 % 20.93 (37) % Natural-gas sales Natural - gas sales increased by $52.6 million for the year ended December 31, 2021, primarily due to increases of (i) $49.0 million at the West Texas complex attributable to an increase in average prices, (ii) $9.6 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes sold, and (iii) $1.8 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). These increases were offset partially by decreases of $5.6 million at the DJ Basin complex and $4.9 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices. Natural-gas sales decreased by $36.0 million for the year ended December 31, 2020, primarily due to decreases of (i) $15.2 million at the DJ Basin complex attributable to a decrease in average prices, (ii) $9.8 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (iii) $6.2 million at the Hilight system resulting from an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown, and (iv) $2.6 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). NGLs sales NGLs sales increased by $99.8 million for the year ended December 31, 2021, primarily due to increases of (i) $73.8 million at the West Texas complex attributable to an increase in average prices, partially offset by a decrease in volumes sold, (ii) $22.3 million at the Chipeta complex and $11.3 million at the Granger complex attributable to increases in average prices, and (iii) $6.5 million at the DJ Basin complex attributable to an increase in average prices and volumes sold. These increases were offset partially by a decrease of $23.0 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). NGLs sales decreased by $111.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $34.0 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (ii) $27.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (iii) $17.7 million at the DJ Basin complex attributable to a decrease in average prices, and (iv) $14.7 million at the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average prices and volumes sold. 73 Table of Contents Equity Income, Net – Related Parties Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Equity income, net – related parties $ 204,645 $ 226,750 (10) % $ 237,518 (5) % Equity income, net – related parties decreased by $22.1 million for the year ended December 31, 2021, primarily due to decreases of (i) $30.8 million at Whitethorn LLC related to commercial activities and lower volumes, (ii) $4.7 million at White Cliffs due to lower volumes, and (iii) $4.0 million at Cactus II due to an increase in depreciation expense recorded in 2021. These decreases were offset partially by increases of (i) $8.1 million at Mont Belvieu JV primarily from a load-reduction electricity credit received in the second quarter of 2021 related to winter storm Uri and (ii) $5.3 million and $4.6 million at Red Bluff Express and Saddlehorn, respectively, resulting from increased volumes. Equity income, net – related parties decreased by $10.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $38.8 million from Whitethorn LLC related to commercial activities and decreased volumes and (ii) $4.2 million from decreased rates at White Cliffs. These decreases were offset partially by increases of (i) $11.4 million related to the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) $5.5 million at TEP, $5.3 million at Ranch Westex, $5.1 million at FRP, and $5.1 million at Red Bluff Express resulting from increased volumes. Cost of Product and Operation and Maintenance Expenses Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Residue purchases $ 146,673 $ 65,193 125 % $ 100,570 (35) % NGLs purchases 160,662 131,964 22 % 331,872 (60) % Other 14,950 (9,069) NM 11,805 (177) % Cost of product 322,285 188,088 71 % 444,247 (58) % Operation and maintenance 581,300 580,874 — % 641,219 (9) % Total Cost of product and Operation and maintenance expenses $ 903,585 $ 768,962 18 % $ 1,085,466 (29) % _________________________________________________________________________________________ NM — Not meaningful Residue purchases Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.6 million at the West Texas complex, $6.7 million at the Chipeta complex, and $6.3 million at the Hilight system attributable to increases in average prices and (ii) $9.2 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $5.2 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). Residue purchases decreased by $35.4 million for the year ended December 31, 2020, primarily due to decreases of (i) $21.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $11.3 million at the DJ Basin complex attributable to average-price decreases, and (iii) $4.3 million at the MGR assets attributable to average-price and purchased-volume decreases. These decreases were offset partially by an increase of $3.2 million at the Chipeta complex primarily due to purchased-volume and average-price increases. 74 Table of Contents NGLs purchases NGLs purchases increased by $28.7 million for the year ended December 31, 2021, primarily due to increases of (i) $40.4 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) $21.5 million at the DJ Basin complex attributable to an increase in average prices and volumes purchased, and (iii) $4.1 million at the Brasada complex attributable to an increase in average prices, partially offset by a decrease in volumes purchased. These increases were offset partially by a decrease of $61.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). NGLs purchases decreased by $199.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $139.5 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $32.6 million at the West Texas complex attributable to average-price decreases, partially offset by purchased-volume increases, (iii) $13.8 million at the Brasada complex attributable to purchased-volume decreases, partially offset by average-price increases, and (iv) $6.9 million at the Chipeta complex attributable to average-price and purchased-volume decreases. Other items Other items increased by $24.0 million for the year ended December 31, 2021, primarily due to increases of $29.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions, partially offset by a decrease of $11.7 million at the DJ Basin complex due to changes in imbalance positions. Other items decreased by $20.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $10.3 million at the West Texas complex due to changes in imbalance positions and (ii) $10.0 million at the DJ Basin complex due to a decrease in transportation costs and changes in imbalance positions. Operation and maintenance expense Operation and maintenance expense increased by $0.4 million for the year ended December 31, 2021, primarily due to an increase of $7.6 million at the West Texas complex, mainly attributable to increased field-related expenses, as well as an increase in utilities expense resulting from the impact of winter storm Uri, partially offset by a decrease of $6.6 million at the Springfield system primarily due to decreased environmental and regulatory expenses. Operation and maintenance expense decreased by $60.3 million for the year ended December 31, 2020, primarily as a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $34.2 million at the West Texas complex primarily resulting from decreased salaries and wages, contract labor and consulting services, and surface maintenance and plant repairs expense, (ii) $6.1 million and $3.3 million at the Springfield and DBM oil systems, respectively, primarily due to decreased salaries and wages and surface maintenance and plant repairs expense, partially offset by increases in other field expenses, (iii) $4.6 million at the Chipeta complex primarily attributable to decreased surface maintenance and plant repairs and utilities expense, and (iv) $3.2 million and $2.4 million at the Hilight system and Granger complex, respectively, primarily due to decreased salaries and wages, surface maintenance and plant repairs, and safety expense. 75 Table of Contents Other Operating Expenses Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) General and administrative $ 195,549 $ 155,769 26 % $ 114,591 36 % Property and other taxes 64,267 68,340 (6) % 61,352 11 % Depreciation and amortization 551,629 491,086 12 % 483,255 2 % Long - lived asset and other impairments 30,543 203,889 (85) % 6,279 NM Goodwill impairment — 441,017 (100) % — NM Total other operating expenses $ 841,988 $ 1,360,101 (38) % $ 665,477 104 % General and administrative expenses General and administrative expenses increased by $39.8 million for the year ended December 31, 2021, primarily due to increases of (i) $23.7 million in personnel costs, including increased bonus-related contributions under our employee savings plan and equity-based compensation expense, and (ii) $16.9 million in contract and consulting costs primarily related to information technology services and fees. General and administrative expenses increased by $41.2 million for the year ended December 31, 2020, primarily due to (i) $21.2 million related to information technology services provided by Occidental to WES and (ii) $16.4 million in personnel costs primarily resulting from WES securing its own dedicated workforce as of December 31, 2019. General and administrative expenses also increased by $6.0 million for the year ended December 31, 2020, primarily due to increases in corporate expenses and professional fees. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For the year ended December 31, 2019, General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements. Effective with the December 2019 Agreements, WES began to incur such costs directly, or via direct charge from Occidental, pursuant to the terms of the Services Agreement. Property and other taxes Property and other taxes decreased by $4.1 million for the year ended December 31, 2021, primarily due to ad valorem tax decreases at the West Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in the DJ Basin due to higher tax rates. Property and other taxes increased by $7.0 million for the year ended December 31, 2020, primarily due to ad valorem tax increases of $6.5 million at the DJ Basin complex due to capital projects being placed into service, including the completion of Latham Train I in November 2019. This increase was offset partially by ad valorem tax decreases in Utah and West Texas due to lower valuations and lower tax rates. Depreciation and amortization expense Depreciation and amortization expense increased by $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. 76 Table of Contents Depreciation and amortization expense increased by $7.8 million for the year ended December 31, 2020, primarily due to increases of (i) $11.9 million and $5.9 million at the West Texas complex and DBM oil system, respectively, resulting from capital projects being placed into service, (ii) $7.8 million of amortization expense related to finance leases, and (iii) $3.3 million for a pipeline in Wyoming due to revisions in cost estimates related to asset retirement obligations. These amounts were offset partially by decreases of (i) $10.6 million at the DJ Basin complex primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system of $32.7 million, offset by increased depreciation expense of $22.1 million for capital projects being placed into service, (ii) $10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii) $5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020. See Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations. Long-lived asset and other impairment expense Long - lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex. Long - lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects. Long-lived asset and other impairment expense for the year ended December 31, 2019, was primarily due to impairments of $4.9 million at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects. For further information on Long - lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Goodwill impairment expense During the three months ended March 31, 2020, an interim goodwill impairment test was performed due to significant unit - price declines triggered by the combined impacts from the global outbreak of COVID - 19 and the oil - market disruption. As a result of the interim impairment test, a goodwill impairment of $441.0 million was recognized for the gathering and processing reporting unit. For additional information, see Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 77 Table of Contents Interest Income – Anadarko Note Receivable and Interest Expense Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Interest income – Anadarko note receivable $ — $ 11,736 (100) % $ 16,900 (31) % Third parties Long - term and short - term debt $ (366,570) $ (369,815) (1) % $ (315,872) 17 % Finance lease liabilities (861) (1,510) (43) % — NM Commitment fees and amortization of debt-related costs (12,705) (13,501) (6) % (12,424) 9 % Capitalized interest 3,624 4,774 (24) % 26,980 (82) % Related parties APCWH Note Payable — — — % (1,833) (100) % Finance lease liabilities — (6) (100) % (137) (96) % Interest expense $ (376,512) $ (380,058) (1) % $ (303,286) 25 % Interest income Interest income - Anadarko note receivable decreased by $11.7 million and $5.2 million for the years ended December 31, 2021 and 2020, respectively, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Interest expense Interest expense decreased by $3.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $21.2 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 on March 1, 2021, (ii) $5.7 million due to lower outstanding balances on the 4.000% Senior Notes due 2022, Floating Rate Notes due 2023, 3.950% Senior Notes due 2025, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021, and (iii) $3.6 million due to lower outstanding borrowings under the RCF in 2021. These decreases were offset partially by (i) an increase of $26.4 million in additional interest incurred from higher effective interest rates resulting from credit - rating downgrades on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and (ii) a decrease of $1.2 million in capitalized interest due to decreased capital expenditures. Interest expense increased by $76.8 million for the year ended December 31, 2020, primarily due to (i) $150.9 million of interest incurred on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and Floating-Rate Senior Notes due 2023 that were issued in January 2020 and (ii) a decrease of $22.2 million in capitalized interest due to decreased capital expenditures. These increases were offset partially by decreases of (i) $75.0 million that occurred as a result of the repayment and termination of the Term loan facility in January 2020 and (ii) $15.5 million due to lower outstanding borrowings under the RCF in 2020. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7. 78 Table of Contents Other Income (Expense), Net Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Other income (expense), net $ (623) $ 1,025 (161) % $ (123,785) (101) % Other income (expense), net increased by $124.8 million for the year ended December 31, 2020, primarily due to non-cash losses of $125.3 million on interest-rate swaps incurred during the year ended December 31, 2019. All outstanding interest-rate swap agreements were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Income (loss) before income taxes $ 934,192 $ 522,850 79 % $ 821,172 (36) % Income tax expense (benefit) (9,807) 5,998 NM 13,472 (55) % Effective tax rate NM 1 % 2 % 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. Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax. Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas. For the year ended December 31, 2021, the variance from the federal statutory rate was primarily impacted by a state margin rate reduction associated with Occidental’s settlement of state audit matters and our Texas margin tax liability. For the year ended December 31, 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability. 79 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2021 2020 Inc/ (Dec) 2019 Inc/ (Dec) Adjusted gross margin for natural - gas assets $ 1,882,726 $ 1,820,926 3 % $ 1,656,041 10 % Adjusted gross margin for crude - oil and NGLs assets 547,134 647,390 (15) % 578,100 12 % Adjusted gross margin for produced - water assets 237,656 249,889 (5) % 193,936 29 % Adjusted gross margin 2,667,516 2,718,205 (2) % 2,428,077 12 % Per - Mcf Adjusted gross margin for natural - gas assets (1) 1.24 1.16 7 % 1.07 8 % Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (2) 2.28 2.54 (10) % 2.44 4 % Per - Bbl Adjusted gross margin for produced - water assets (3) 0.93 0.98 (5) % 0.97 1 % Adjusted EBITDA 1,946,690 2,030,366 (4) % 1,719,090 18 % Free cash flow 1,490,128 1,226,588 21 % 36,709 NM _________________________________________________________________________________________ (1) Average for period. Calculated as Adjusted gross margin for natural - gas assets, divided by total throughput (MMcf/d) attributable to WES for natural - gas assets. (2) Average for period. Calculated as Adjusted gross margin for crude - oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude - oil and NGLs assets. (3) Average for period. Calculated as Adjusted gross margin for produced - water assets, divided by total throughput (MBbls/d) attributable to WES for produced - water assets. 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). To facilitate investor and industry analyst comparisons between us and our peers, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets . Adjusted gross margin decreased by $50.7 million for the year ended December 31, 2021, primarily due to (i) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, (ii) a decrease in distributions from Whitethorn LLC and Cactus II, (iii) decreased throughput and an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), (iv) the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020 and decreased throughput at the Bison treating facility, which was sold to a third party during the second quarter of 2021, (v) a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the DBM water systems, and (vi) decreased throughput on certain fee-based contracts at the DJ Basin complex. These decreases were offset partially by (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex, (ii) cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021, at the Springfield system, and (iii) an increase in distributions from Red Bluff Express and Ranch Westex. 80 Table of Contents Adjusted gross margin increased by $290.1 million for the year ended December 31, 2020, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes and the DBM water systems, (ii) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system, (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, (iv) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020, and (v) annual cost-of-service rate adjustments at the Springfield system that increased revenues in the fourth quarter of 2020 and decreased revenues in the fourth quarter of 2019 (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC related to commercial activities and (ii) a decrease at the Hilight system resulting from lower throughput and an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown. Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 for the year ended December 31, 2021, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex and (ii) a higher cost - of - service rate effective January 1, 2021, at the Springfield system. These increases were offset partially by decreased throughput on certain fee-based contracts at the DJ Basin complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets. Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.09 for the year ended December 31, 2020, primarily due to increased throughput at the West Texas and DJ Basin complexes, which have higher-than-average per-Mcf margins as compared to our other natural-gas assets. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets decreased by $0.26 for the year ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system and (ii) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets. These decreases were offset partially by a higher cost - of - service rate effective January 1, 2021, at the Springfield system. Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.10 for the year ended December 31, 2020, primarily due to (i) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by a decrease in distributions from Whitethorn LLC related to commercial activities. Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021. Adjusted EBITDA. 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 81 Table of Contents • the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments. These amounts were offset partially by (i) a $104.6 million increase in total revenues and other and (ii) a $4.1 million decrease in property taxes. Adjusted EBITDA increased by $311.3 million for the year ended December 31, 2020, primarily due to (i) a $256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a $60.3 million decrease in operation and maintenance expenses, (iii) a $26.4 million increase in total revenues and other, and (iv) a $14.0 million increase in distributions from equity investments. These amounts were offset partially by (i) a $33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a $7.0 million increase in property taxes. The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7). Free cash flow. 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. Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings. Free cash flow increased by $1,189.9 million for the year ended December 31, 2020, primarily due to (i) a decrease of $765.7 million in capital expenditures, (ii) an increase of $313.3 million in net cash provided by operating activities, and (iii) a decrease of $109.0 million in contributions to equity investments. See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. 82 Table of Contents Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure used by us that is most directly comparable to Adjusted gross margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to Free cash flow is net cash provided by operating activities. 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 2021 2020 2019 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 2,877,155 $ 2,772,592 $ 2,746,174 Less: Cost of product 322,285 188,088 444,247 Depreciation and amortization 551,629 491,086 483,255 Gross margin 2,003,241 2,093,418 1,818,672 Add: Distributions from equity investments 254,901 278,797 264,828 Depreciation and amortization 551,629 491,086 483,255 Less: Reimbursed electricity-related charges recorded as revenues 74,405 79,261 74,629 Adjusted gross margin attributable to noncontrolling interests (1) 67,850 65,835 64,049 Adjusted gross margin $ 2,667,516 $ 2,718,205 $ 2,428,077 Adjusted gross margin for natural - gas assets $ 1,882,726 $ 1,820,926 $ 1,656,041 Adjusted gross margin for crude - oil and NGLs assets 547,134 647,390 578,100 Adjusted gross margin for produced - water assets 237,656 249,889 193,936 _________________________________________________________________________________________ (1) For all periods presented, includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% Occidental subsidiary - owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests. 83 Table of Contents Year Ended December 31, thousands 2021 2020 2019 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 943,999 $ 516,852 $ 807,700 Add: Distributions from equity investments 254,901 278,797 264,828 Non - cash equity - based compensation expense 27,676 22,462 14,392 Interest expense 376,512 380,058 303,286 Income tax expense 4,403 10,278 13,472 Depreciation and amortization 551,629 491,086 483,255 Impairments (1) 30,543 644,906 6,279 Other expense 1,468 1,953 161,813 Less: Gain (loss) on divestiture and other, net 44 8,634 (1,406) Gain (loss) on early extinguishment of debt (24,944) 11,234 — Equity income, net – related parties 204,645 226,750 237,518 Interest income – Anadarko note receivable — 11,736 16,900 Other income 585 2,785 37,792 Income tax benefit 14,210 4,280 — Adjusted EBITDA attributable to noncontrolling interests (2) 49,901 50,607 45,131 Adjusted EBITDA $ 1,946,690 $ 2,030,366 $ 1,719,090 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 Interest (income) expense, net 376,512 368,322 286,386 Uncontributed cash-based compensation awards — — (1,102) Accretion and amortization of long - term obligations, net (7,635) (8,654) (8,441) Current income tax expense (benefit) (37) 2,702 5,863 Other (income) expense, net (3) 623 (1,025) (1,549) Cash paid to settle interest - rate swaps — 25,621 107,685 Distributions from equity investments in excess of cumulative earnings – related parties 41,385 32,160 30,256 Changes in assets and liabilities: Accounts receivable, net (16,366) 193,688 45,033 Accounts and imbalance payables and accrued liabilities, net (114,887) (144,437) 30,866 Other items, net (49,856) (24,822) (54,876) Adjusted EBITDA attributable to noncontrolling interests (2) (49,901) (50,607) (45,131) Adjusted EBITDA $ 1,946,690 $ 2,030,366 $ 1,719,090 Cash flow information Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 Net cash used in investing activities (257,538) (448,254) (3,387,853) Net cash provided by (used in) financing activities (1,752,237) (844,204) 2,071,573 _________________________________________________________________________________________ (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% Occidental subsidiary - owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests. (3) Excludes net non-cash losses on interest-rate swaps of $25.6 million for the year ended December 31, 2019. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 84 Table of Contents Year Ended December 31, thousands 2021 2020 2019 Reconciliation of Net cash provided by operating activities to Free cash flow Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 Less: Capital expenditures 313,674 423,602 1,189,254 Contributions to equity investments – related parties 4,435 19,388 128,393 Add: Distributions from equity investments in excess of cumulative earnings – related parties 41,385 32,160 30,256 Free cash flow $ 1,490,128 $ 1,226,588 $ 36,709 Cash flow information Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 Net cash used in investing activities (257,538) (448,254) (3,387,853) Net cash provided by (used in) financing activities (1,752,237) (844,204) 2,071,573 GENERAL TRENDS AND OUTLOOK We expect our business to continue 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 the first quarter of 2020, oil and natural - gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in demand resulting from the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19. These market dynamics had an adverse impact on producers that provide throughput into our systems, and we experienced decreased throughput at many of our locations. For example, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2020 ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, and prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021. Although commodity prices have rebounded to pre-pandemic levels, the extent and duration of the recent commodity - price volatility cannot be predicted, and potential impacts to our business include the following: • We have exposure to increased credit risk to the extent any of our customers, including Occidental, is in financial distress. See Liquidity and Capital Resources—Credit risk within this Item 7 for additional information. • An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most - recent four - consecutive fiscal quarters ending on such day) . See Liquidity and Capital Resources—Debt and credit facilities within this Item 7 for additional information. • As of December 31, 2021, it is reasonably possible that future commodity - price declines, prolonged depression of commodity prices, changes to producers’ drilling plans in response to lower prices, and potential producer bankruptcies could result in future long - lived asset impairments. 85 Table of Contents To the extent producers continue with development plans in our areas of operation, we intend to continue to connect new wells or production facilities to our systems to maintain throughput on our systems and mitigate the impact of production declines. However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers. Additionally, we intend to continue to evaluate the crude - oil, NGLs, and natural - gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility. Liquidity and access to capital markets. Historically, we have accessed the debt and equity capital markets to raise money to fund growth projects, acquisitions, and to refinance long-term debt. 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 becoming more frequent. 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. More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. A significant increase in inflation would raise our costs for labor, materials, and services, which could increase our operating costs and capital expenditures materially and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees. Impact of interest rates. Overall, short- and long-term interest rates increased during 2021, but remained low relative to historical averages. Any future increases in interest rates likely will result in an increase in financing costs. 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. 86 Table of Contents LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include quarterly distributions, debt service, customary operating expenses, and capital expenditures. Our sources of liquidity as of December 31, 2021, 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 pay distributions or to fund 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) reserves to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. 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 2021 of $0.32700 per unit, or $134.7 million in the aggregate. The cash distribution was paid on February 14, 2022, to our unitholders of record at the close of business on January 31, 2022. In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. During the year ended December 31, 2021, we repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million, fulfilling the entire $250.0 million authorized program. The units were canceled immediately upon receipt. In February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. 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. For the year ended December 31, 2022, we estimate that our total capital expenditures will be between $375.0 million to $475.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Management continuously monitors our leverage position and coordinates our capital expenditures and quarterly distributions with expected cash inflows and projected debt-service requirements. 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, 2021, we had a $455.4 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Our working capital deficit was primarily due to the 4.000% Senior Notes due 2022 of $502.1 million being classified as short-term debt on the consolidated balance sheet as of December 31, 2021. As of December 31, 2021, there was $2.0 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. 87 Table of Contents Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures includes maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets; and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels. Capital expenditures 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 2021 2020 2019 Acquisitions $ — $ — $ 2,100,804 Capital expenditures (1) 313,674 423,602 1,189,254 Capital incurred (1) 324,150 307,644 1,055,151 _________________________________________________________________________________________ (1) For the years ended December 31, 2021, 2020, and 2019 included $3.6 million, $4.8 million, and $23.3 million, respectively, of capitalized interest. Acquisitions during 2019 included AMA and the 30% interest in Red Bluff Express. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Capital expenditures decreased by $109.9 million for the year ended December 31, 2021, primarily due to decreases of (i) $43.9 million at the DJ Basin complex primarily related to the completion of Latham Train II that commenced operations in the first quarter of 2020, and decreases in pipeline, well connection, and compression projects, (ii) $22.6 million at the West Texas complex primarily attributable to decreases in facility expansion, (iii) $15.7 million at the DBM oil system primarily related to the completion of the Loving ROTF Trains III and IV that commenced operations during the first and third quarters of 2020, respectively, and decreases in pipeline and well connection projects, (iv) $10.0 million at the DBM water systems primarily due to reduced construction of additional water - disposal facilities and gathering projects, and (v) $4.8 million at the DJ Basin oil system primarily related to decreases in pipeline projects. Capital expenditures decreased by $765.7 million for the year ended December 31, 2020, primarily due to decreases of (i) $362.5 million at the DJ Basin complex primarily related to the completion of Latham Trains I and II that commenced operations in November 2019 and February 2020, respectively, as well as decreases in pipeline, well connection, and compression projects, (ii) $186.8 million at the West Texas complex primarily attributable to the completion of Mentone Train II that commenced operations in March 2019 and decreases in pipeline and well connection projects, (iii) $107.5 million at the DBM oil system primarily related to the completion of the Loving ROTF Train III that commenced operations in January 2020 and decreases in pipeline and well connection projects, and (iv) $90.4 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects. 88 Table of Contents Historical cash flow . The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities: Year Ended December 31, thousands 2021 2020 2019 Net cash provided by (used in): Operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 Investing activities (257,538) (448,254) (3,387,853) Financing activities (1,752,237) (844,204) 2,071,573 Net increase (decrease) in cash and cash equivalents $ (242,923) $ 344,960 $ 7,820 Operating activities . Net cash provided by operating activities increased for the year ended December 31, 2021, primarily due to (i) the impact of changes in assets and liabilities, (ii) cash paid during the year ended December 31, 2020, to settle interest-rate swaps, and (iii) lower interest expense. These increases were offset partially by (i) lower cash operating income, (ii) lower distributions from equity-investment earnings, and (iii) lower interest income. Net cash provided by operating activities increased for the year ended December 31, 2020, primarily due to (i) higher cash operating income, (ii) lower cash paid to settle interest-rate swap agreements, and (iii) higher distributions from equity-investment earnings. These increases were offset partially by higher interest expense. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities . Net cash used in investing activities for the year ended December 31, 2021, included the following: • $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; • $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. Net cash used in investing activities for the year ended December 31, 2019, included the following: • $2.0 billion of cash paid for the acquisition of AMA; • $1.2 billion of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM water systems; 89 Table of Contents • $128.4 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for construction activities; • $92.5 million of cash paid for the acquisition of our interest in Red Bluff Express; and • $30.3 million of distributions received from equity investments in excess of cumulative earnings. Financing activities . Net cash used in financing activities for the year ended December 31, 2021, included the following: • $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; • $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; • $6.5 million of finance lease payments; • $480.0 million of borrowings under the RCF, which were used for general partnership purposes and to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer; 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; 90 Table of Contents • $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. Net cash provided by financing activities for the year ended December 31, 2019, included the following: • $3.0 billion of borrowings under the Term loan facility, net of issuance costs, which were used to fund the acquisition of AMA, to repay the APCWH Note Payable, and to repay amounts outstanding under the RCF; • $1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including the funding of capital expenditures; • $458.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA; • $11.0 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems; • $7.4 million of capital contributions from Anadarko related to the above-market component of swap agreements; • $1.0 billion of repayments of outstanding borrowings under the RCF; • $969.1 million of distributions paid to WES unitholders; • $439.6 million of repayments of the total outstanding balance under the APCWH Note Payable; • $118.2 million of distributions paid to the noncontrolling interest owners of WES Operating; • $28.0 million of repayments of the total outstanding balance under the WGP RCF, which matured in March 2019; and • $9.7 million of distributions paid to the noncontrolling interest owner of Chipeta. 91 Table of Contents Debt and credit facilities. As of December 31, 2021, the carrying value of outstanding debt was $6.9 billion and we have estimated future interest and RCF fee payments totaling $342.6 million in 2022. 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 4.542%, 5.424%, and 6.629%, respectively, at December 31, 2021. The interest rate on the Floating - Rate Senior Notes was 1.97% at December 31, 2021. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. In August 2021 and December 2021, Standard and Poor’s (“S&P”) and Fitch Ratings, respectively, upgraded WES Operating’s long-term debt from “BB” to “BB+.” In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” As a result of these upgrades, annualized borrowing costs will decrease by $23.6 million. During the third quarter of 2021, WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer. During the first quarter of 2021, WES Operating redeemed the total principal amount outstanding of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture. During the year ended December 31, 2021, losses of $24.9 million were recognized for the retirement of these notes. As of December 31, 2021, the 4.000% Senior Notes due 2022 were classified as short-term debt on the consolidated balance sheet. At December 31, 2021, WES Operating was in compliance with all covenants under the relevant governing indentures. 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. WES Operating’s $2.0 billion senior unsecured revolving credit facility is expandable to a maximum of $2.5 billion, and matures in February 2025 for each extending lender. The non - extending lender’s commitments mature in February 2024 and represent $100.0 million out of $2.0 billion of total commitments from all lenders. As of December 31, 2021, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF. As of December 31, 2021, the interest rate on any outstanding RCF borrowings was 1.60% and the facility - fee rate was 0.25%. The RCF bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating. 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. At December 31, 2021, WES Operating was in compliance with all covenants under the RCF. 92 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, 2021, we have future finance-lease payments of $3.9 million in 2022 and a total of $1.6 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, 2021, we expect to incur asset retirement costs of $9.9 million in 2022 and a total of $298.3 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, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors. As of December 31, 2021, we have future operating-lease payments of $10.7 million in 2022 and a total of $44.9 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, 2021, we have estimated future minimum-volume-commitment fees of $3.7 million in 2022 and a total of $11.1 million in years thereafter. 93 Table of Contents Credit risk . We bear credit risk through exposure to non - payment or non - performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non - payment or non - performance results from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas - imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. 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; the contribution agreements; or the Services Agreement. 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 2021 2020 2019 Net income (loss) attributable to WES $ 916,292 $ 527,012 $ 697,241 Limited partner interests in WES Operating not held by WES (1) 18,765 10,830 103,364 General and administrative expenses (2) 2,932 3,552 6,819 Other income (expense), net (11) (17) (79) Income taxes 9 — — Interest expense — — 245 Net income (loss) attributable to WES Operating $ 937,987 $ 541,377 $ 807,590 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2021, 2020, and 2019. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. 94 Table of Contents 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 2021 2020 2019 WES net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100 General and administrative expenses (1) 2,932 3,552 6,819 Non - cash equity - based compensation expense 6,912 (7,858) (1,259) Changes in working capital (11,315) 7,556 2,383 Other income (expense), net (11) (17) (79) Income taxes 9 — — Interest expense — — 245 Debt related amortization and other items, net — — (20) WES Operating net cash provided by operating activities $ 1,765,379 $ 1,640,651 $ 1,332,189 WES net cash provided by (used in) financing activities $ (1,752,237) $ (844,204) $ 2,071,573 Distributions to WES unitholders (2) 533,758 695,834 969,073 Distributions to WES from WES Operating (3) (734,034) (756,112) (1,006,163) Increase (decrease) in outstanding checks (68) (35) — Unit repurchases 217,465 32,535 — Registration expenses related to the issuance of WES common units — — 855 WGP RCF repayments — — 28,000 Other 4,336 — — WES Operating net cash provided by (used in) financing activities $ (1,730,780) $ (871,982) $ 2,063,338 _________________________________________________________________________________________ (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 . 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 . WES Operating LTIP. Concurrent with the Merger closing, we assumed the Western Gas Partners, LP 2017 Long-Term Incentive Plan. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information. 95 Table of Contents 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. Service revenues – fee based. Certain of our midstream services contracts have minimum-volume-commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost-of-service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate based on the total expected variable consideration under the contract. The cost-of-service rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses. If management determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal. See Revenue and cost of product in Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially recorded at Anadarko’s historic carrying value. 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. 96 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 $30.5 million (which includes an other-than-temporary impairment expense of an equity investment), $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), and $6.3 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 9—Property, Plant, and Equipment and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2021, 2020, and 2019. 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, and interest-rate swaps. 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. 97 Table of Contents