Western Midstream Partners, LP 10-Q

Item 2. 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 I, Item 1 of this quarterly report, and the historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of the 2021 Form 10-K as filed with the SEC on February 23, 2022. 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 March 31, 2022 (see Note 6—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental. CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS We have made in this Form 10-Q, and may make in other public filings, press releases, and statements by management, forward - looking statements concerning our operations, economic performance, and financial condition. These forward - looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward - looking” information. Although we and our general partner believe that the expectations reflected in our forward - looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward - looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following: • our ability to pay distributions to our unitholders; • our assumptions about the energy market; • future throughput (including Occidental production) that is gathered or processed by, or transported through, our assets; • our operating results; • competitive conditions; • technology; • the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets; • the supply of, demand for, and price of oil, natural gas, NGLs, and related products or services; • commodity - price risks inherent in percent - of - proceeds, percent - of - product, and keep - whole contracts; • weather and natural disasters; • inflation; • the availability of goods and services; • general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business; 33 Table of Contents • federal, state, and local laws and state - approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic - fracturing activities or other oil and natural - gas development or operations; • environmental liabilities; • legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes; • changes in the financial or operational condition of Occidental; • the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties; • changes in Occidental’s capital program, corporate strategy, or other desired areas of focus; • our commitments to capital projects; • our ability to access liquidity under the RCF; • our ability to repay debt; • the resolution of litigation or other disputes; • conflicts of interest among us and our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs and our future business opportunities; • our ability to maintain and/or obtain rights to operate our assets on land owned by third parties; • our ability to acquire assets on acceptable terms from third parties; • non - payment or non - performance of significant customers, including under gathering, processing, transportation, and disposal agreements; • the timing, amount, and terms of future issuances of equity and debt securities; • the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; • the economic uncertainty from the worldwide outbreak of the coronavirus (“COVID - 19”); • cyber attacks or security breaches; and • other factors discussed below, in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the 2021 Form 10 - K, in our quarterly reports on Form 10 - Q, and in our other public filings and press releases. Risk factors and other factors noted throughout or incorporated by reference in this Form 10-Q could cause actual results to differ materially from those contained in any forward - looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward - looking statements, whether as a result of new information, future events, or otherwise. 34 Table of Contents 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 March 31, 2022, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems (1) 17 2 3 1 Treating facilities 37 3 — — Natural - gas processing plants/trains 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 three months ended March 31, 2022, included the following: • We repurchased 225,355 common units on the open market for an aggregate purchase price of $5.1 million. • Our first - quarter 2022 per - unit distribution of $0.50000 increased $0.17300 from the fourth - quarter 2021 per - unit distribution of $0.32700. • Natural - gas throughput attributable to WES totaled 4,058 MMcf/d for the three months ended March 31, 2022, representing a 3% decrease compared to the three months ended December 31, 2021, and no change compared to the three months ended March 31, 2021. • Crude - oil and NGLs throughput attributable to WES totaled 675 MBbls/d for the three months ended March 31, 2022, representing a 4% decrease and a 12% increase compared to the three months ended December 31, 2021, and March 31, 2021, respectively. • Produced - water throughput attributable to WES totaled 751 MBbls/d for the three months ended March 31, 2022, representing a 5% decrease and a 26% increase compared to the three months ended December 31, 2021, and March 31, 2021, respectively. • Gross margin was $550.9 million for the three months ended March 31, 2022, representing a 10% increase and a 21% increase compared to the three months ended December 31, 2021, and March 31, 2021, respectively. See Key Performance Metrics within this Item 2. • Adjusted gross margin for natural - gas assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $1.34 per Mcf for the three months ended March 31, 2022, representing a 6% increase and a 13% increase compared to the three months ended December 31, 2021, and March 31, 2021, respectively. 35 Table of Contents • Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $2.44 per Bbl for the three months ended March 31, 2022, representing a 37% increase compared to the three months ended December 31, 2021, and no change compared to the three months ended March 31, 2021. • Adjusted gross margin for produced - water assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $1.00 per Bbl for the three months ended March 31, 2022, representing a 9% increase compared to the three months ended December 31, 2021, and March 31, 2021. The following table provides additional information on throughput for the periods presented below: Three Months Ended March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,326 1,370 (3) % 1,133 17 % DJ Basin 1,321 1,349 (2) % 1,344 (2) % Equity investments 479 513 (7) % 439 9 % Other 1,084 1,127 (4) % 1,279 (15) % Total throughput for natural - gas assets 4,210 4,359 (3) % 4,195 — % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 192 199 (4) % 162 19 % DJ Basin 88 92 (4) % 82 7 % Equity investments 374 393 (5) % 337 11 % Other 35 32 9 % 35 — % Total throughput for crude - oil and NGLs assets 689 716 (4) % 616 12 % Throughput for produced-water assets (MBbls/d) Delaware Basin 766 808 (5) % 607 26 % Total throughput for produced - water assets 766 808 (5) % 607 26 % 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 2020, oil and natural - gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19. In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine. For example, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021, and prices during the first quarter of 2022 ranged from a low of $76.08 per barrel in January 2022 to a high of $123.70 per barrel in March 2022. The extent and duration of the recent commodity - price volatility cannot be predicted. 36 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 or increase throughput on our systems and mitigate the impact of production declines. However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers, any capacity constraints, and the availability of downstream-takeaway alternatives. In some cases, we take ownership of volumes at the tailgate of our plants based on certain contractual arrangements with our producer customers, which introduces additional commodity-price exposure. Additionally, we intend to continue to evaluate the crude - oil, NGLs, and natural - gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility. Impact of inflation and supply-chain disruptions. Although inflation in the United States has been relatively low in recent years, the U.S. economy currently is experiencing significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine. More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued increases in inflation will raise our costs for labor, materials, and services, which will 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 and continued to increase during the first quarter of 2022. 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. ACQUISITIONS AND DIVESTITURES Bison facilities. In October 2020, we 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. 37 Table of Contents RESULTS OF OPERATIONS OPERATING RESULTS The following tables and discussion present a summary of our results of operations: Three Months Ended thousands March 31, 2022 December 31, 2021 March 31, 2021 Total revenues and other (1) $ 758,297 $ 719,210 $ 674,974 Equity income, net – related parties 49,607 45,308 52,165 Total operating expenses (1) 403,450 438,563 434,220 Gain (loss) on divestiture and other, net 370 (234) (583) Operating income (loss) 404,824 325,721 292,336 Interest expense (85,455) (89,472) (98,493) Gain (loss) on early extinguishment of debt — — (289) Other income (expense), net 106 390 (1,207) Income (loss) before income taxes 319,475 236,639 192,347 Income tax expense (benefit) 1,805 (14,210) 1,112 Net income (loss) 317,670 250,849 191,235 Net income (loss) attributable to noncontrolling interests 8,953 7,332 5,444 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 308,717 $ 243,517 $ 185,791 _________________________________________________________________________________________ (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 5—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. (2) For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 2. For purposes of the following discussion, any increases or decreases refer to the comparison of the three months ended March 31, 2022, to the three months ended December 31, 2021, or to the three months ended March 31, 2021, as applicable. 38 Table of Contents Throughput Three Months Ended March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 406 437 (7) % 519 (22) % Processing 3,325 3,409 (2) % 3,237 3 % Equity investments (1) 479 513 (7) % 439 9 % Total throughput 4,210 4,359 (3) % 4,195 — % Throughput attributable to noncontrolling interests (2) 152 155 (2) % 150 1 % Total throughput attributable to WES for natural - gas assets 4,058 4,204 (3) % 4,045 — % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 315 323 (2) % 279 13 % Equity investments (3) 374 393 (5) % 337 11 % Total throughput 689 716 (4) % 616 12 % Throughput attributable to noncontrolling interests (2) 14 14 — % 12 17 % Total throughput attributable to WES for crude - oil and NGLs assets 675 702 (4) % 604 12 % Throughput for produced-water assets (MBbls/d) Gathering and disposal 766 808 (5) % 607 26 % Throughput attributable to noncontrolling interests (2) 15 16 (6) % 12 25 % Total throughput attributable to WES for produced - water assets 751 792 (5) % 595 26 % _________________________________________________________________________________________ (1) Represents the 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 31 MMcf/d compared to the three months ended December 31, 2021, primarily due to decreased production in areas around the Marcellus Interest systems. Gathering, treating, and transportation throughput decreased by 113 MMcf/d compared to the three months ended March 31, 2021, primarily due (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021 and (ii) production declines in areas around the Marcellus Interest systems. Processing throughput decreased by 84 MMcf/d compared to the three months ended December 31, 2021, primarily due to (i) lower volumes at the West Texas complex due to production declines in the area and the impacts of inclement weather in the first quarter of 2022 and (ii) lower volumes at the DJ Basin and Granger complexes due to production declines in the areas. Processing throughput increased by 88 MMcf/d compared to the three months ended March 31, 2021, primarily due to higher volumes at the West Texas complex resulting from the impact of winter storm Uri during the first quarter of 2021, partially offset by lower volumes at the DJ Basin, Granger, and Brasada complexes due to production declines in the areas. 39 Table of Contents Equity - investment throughput decreased by 34 MMcf/d compared to the three months ended December 31, 2021, primarily due to decreased volumes at the Mi Vida and Ranch Westex plants and on Red Bluff Express. Equity - investment throughput increased by 40 MMcf/d compared to the three months ended March 31, 2021, primarily due to increased volumes on Red Bluff Express and at the Mi Vida plant resulting from the impact of winter storm Uri during the first quarter of 2021. These increases were offset partially by (i) decreased volumes at the Rendezvous system due to production declines in the area and (ii) decreased volumes at Ranch Westex plant. Crude-oil and NGLs assets Gathering, treating, and transportation throughput decreased by 8 MBbls/d compared to the three months ended December 31, 2021, primarily due to lower volumes at the DBM oil system resulting from the impacts of inclement weather in the first quarter of 2022. Gathering, treating, and transportation throughput increased by 36 MBbls/d compared to the three months ended March 31, 2021, primarily due (i) higher volumes at the DBM oil system resulting from the impact of winter storm Uri during the first quarter of 2021 and (ii) increased production in areas around the DJ Basin oil system. Equity - investment throughput decreased by 19 MBbls/d compared to the three months ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline. Equity - investment throughput increased by 37 MBbls/d compared to the three months ended March 31, 2021, primarily due to (i) increased volumes on FRP and the Saddlehorn pipeline resulting from increased pipeline commitments and (ii) increased volumes on the Whitethorn pipeline. Produced-water assets Gathering and disposal throughput decreased by 42 MBbls/d compared to the three months ended December 31, 2021, due to decreased volumes at the DBM water systems resulting from lower production and the impacts of inclement weather in the first quarter of 2022. Gathering and disposal throughput increased by 159 MBbls/d compared to the three months ended March 31, 2021, due to (i) new third-party connections brought online during the fourth quarter of 2021 and (ii) the impact of winter storm Uri during the first quarter of 2021. 40 Table of Contents Service Revenues Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Service revenues – fee based $ 631,598 $ 621,093 2 % $ 572,275 10 % Service revenues – product based 40,867 34,317 19 % 31,652 29 % Total service revenues $ 672,465 $ 655,410 3 % $ 603,927 11 % Service revenues – fee based Service revenues – fee based increased by $10.5 million compared to the three months ended December 31, 2021, primarily due to increases of (i) $28.7 million at the DJ Basin oil system due to an annual cost-of-service rate adjustment that decreased revenue during the fourth quarter of 2021, partially offset by decreased throughput, (ii) $7.6 million at the DBM oil system due to the treatment of lease revenue under the operating and maintenance agreement with Occidental that was terminated effective December 31, 2021, partially offset by decreased throughput, and (iii) $3.1 million at the Marcellus Interest systems due to an increase in the average gathering fee effective January 1, 2022, partially offset by decreased throughput. These increases were offset partially by decreases of (i) $18.8 million at the West Texas complex due to a lower cost-of-service rate effective January 1, 2022, and decreased throughput, (ii) $4.9 million at the DJ Basin complex due to decreased throughput, and (iii) $4.8 million at the Springfield system due to an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2021, in addition to a lower cost - of - service rate effective January 1, 2022. Service revenues – fee based increased by $59.3 million compared to the three months ended March 31, 2021, primarily due to increases of (i) $22.1 million at the West Texas complex due to increased throughput, including the impact of winter storm Uri during the first quarter of 2021, partially offset by a lower cost-of-service rate effective January 1, 2022, and (ii) $17.5 million at the DBM water systems and $15.7 million at the DBM oil system due to increased throughput, including the impact of winter storm Uri during the first quarter of 2021. Service revenues – product based Service revenues – product based increased by $6.6 million compared to the three months ended December 31, 2021, primarily due to increases of (i) $2.7 million at the West Texas complex due to increased volumes and prices for certain third-party contracts and (ii) $2.3 million at the DJ Basin complex and $0.7 million at the Chipeta complex due to increased prices. Service revenues – product based increased by $9.2 million compared to the three months ended March 31, 2021, primarily due to increases of (i) $3.9 million at the DJ Basin complex, $2.3 million at the Chipeta complex, and $1.4 million at the Granger complex due to increased prices, and (ii) $1.4 million at the DBM water systems due to increased prices and volumes. 41 Table of Contents Product Sales Three Months Ended thousands except percentages and per-unit amounts March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Natural - gas sales $ 19,071 $ 15,337 24 % $ 21,419 (11) % NGLs sales 66,518 48,251 38 % 49,386 35 % Total Product sales $ 85,589 $ 63,588 35 % $ 70,805 21 % Per - unit gross average sales price: Natural gas (per Mcf) $ 4.38 $ 4.60 (5) % $ 5.98 (27) % NGLs (per Bbl) 46.48 42.05 11 % 28.42 64 % Natural-gas sales Natural - gas sales increased by $3.7 million compared to the three months ended December 31, 2021, primarily due to an increase of $2.3 million at the West Texas complex due to increased volumes sold as a result of throughput increases on certain third-party contracts. NGLs sales NGLs sales increased by $18.3 million compared to the three months ended December 31, 2021, primarily due to increases of (i) $8.6 million at the West Texas complex due to increases in average prices and volumes sold and (ii) $5.4 million at the DJ Basin complex and $4.2 million at the Chipeta complex due to an increase in average prices. NGLs sales increased by $17.1 million compared to the three months ended March 31, 2021, primarily due to increases of (i) $8.1 million at the Chipeta complex, $1.4 million at the DBM water systems, and $1.2 million at the Hilight complex attributable to increases in average prices and volumes sold, and (ii) $2.8 million at the Granger complex and $2.0 million at the DJ Basin complex due to an increase in average prices. Equity Income, Net – Related Parties Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Equity income, net – related parties $ 49,607 $ 45,308 9 % $ 52,165 (5) % Equity income, net – related parties increased by $4.3 million compared to the three months ended December 31, 2021, primarily due to increases of (i) $1.7 million at Whitethorn LLC related to commercial activities and (ii) $1.2 million at Mi Vida related to decreases in certain expenses during the current period. Equity income, net – related parties decreased by $2.6 million compared to the three months ended March 31, 2021, primarily due to decreases of (i) $3.0 million at Saddlehorn Pipeline related to contracts with higher tariff rates expiring in August 2021 and (ii) $2.7 million at Cactus II related to a decrease in trunk revenues. These decreases were offset partially by an increase of $2.2 million at Mi Vida due to higher volumes. 42 Table of Contents Cost of Product and Operation and Maintenance Expenses Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Residue purchases $ 34,992 $ 38,471 (9) % $ 55,745 (37) % NGLs purchases 70,404 62,578 13 % 30,907 128 % Other (32,548) (29,009) 12 % 2,317 NM Cost of product 72,848 72,040 1 % 88,969 (18) % Operation and maintenance 128,976 147,102 (12) % 140,332 (8) % Total Cost of product and Operation and maintenance expenses $ 201,824 $ 219,142 (8) % $ 229,301 (12) % _________________________________________________________________________________________ NM — Not meaningful Residue purchases Residue purchases decreased by $3.5 million compared to the three months ended December 31, 2021, primarily due to a decrease of $2.0 million at the West Texas complex attributable to decreased volumes for certain third-party contracts. Residue purchases decreased by $20.8 million compared to the three months ended March 31, 2021, primarily due to decreases of $13.2 million at the West Texas complex, $3.3 million at the DJ Basin complex, and $3.0 million at the Hilight system attributable to decreases in average prices. NGLs purchases NGLs purchases increased by $7.8 million compared to the three months ended December 31, 2021, primarily due to an increase of $5.1 million at the West Texas complex attributable to an increase in average prices. NGLs purchases increased by $39.5 million compared to the three months ended March 31, 2021, primarily due to increases of $19.0 million at the West Texas complex, $12.3 million at the DJ Basin complex, and $3.6 million at the Chipeta complex attributable to increases in average prices. Other items Other items decreased by $3.5 million compared to the three months ended December 31, 2021, primarily due to decreases of $3.7 million at the West Texas complex and $3.0 million at the DJ Basin complex, primarily due to changes in imbalance positions, partially offset by an increase of $3.2 million at the Chipeta complex due to a change in imbalance positions. Other items decreased by $34.9 million compared to the three months ended March 31, 2021, primarily due to decreases of $29.3 million at the West Texas complex and $6.9 million at the DJ Basin complex, primarily due to changes in imbalance positions. Operation and maintenance expense Operation and maintenance expense decreased by $18.1 million compared to the three months ended December 31, 2021, primarily due to decreases of (i) $14.1 million at the West Texas complex attributable to a sales tax accrual in the fourth quarter of 2021 on compressor rentals and reduced utilities and salaries and wages expense, (ii) $7.3 million at the DJ Basin complex due to lower utilities expense and surface maintenance and plant repairs, and (iii) $4.3 million at the DBM water systems attributable to lower surface-use fees and utilities expense. These decreases were offset partially by an increase of $3.1 million at the DBM oil system, primarily due to an increase in salaries and wages. Operation and maintenance expense decreased by $11.4 million compared to the three months ended March 31, 2021, primarily due to decreases of $5.0 million at the DBM oil system and $4.4 million at the West Texas complex attributable to reduced utilities expense and contract and consulting costs. 43 Table of Contents Other Operating Expenses Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) General and administrative $ 48,602 $ 55,576 (13) % $ 45,116 8 % Property and other taxes 18,442 18,275 1 % 14,384 28 % Depreciation and amortization 134,582 144,225 (7) % 130,553 3 % Long - lived asset and other impairments — 1,345 (100) % 14,866 (100) % Total other operating expenses $ 201,626 $ 219,421 (8) % $ 204,919 (2) % General and administrative expenses General and administrative expenses decreased by $7.0 million compared to the three months ended December 31, 2021, primarily due to decreases in consulting costs and corporate expenses primarily related to information technology services and legal fees. General and administrative expenses increased by $3.5 million compared to the three months ended March 31, 2021, primarily due to increases of $3.3 million in personnel costs, including increased bonus-related expenses and equity-based compensation expense. Property and other taxes Property and other taxes increased by $4.1 million compared to the three months ended March 31, 2021, primarily due to ad valorem tax increases at the DJ Basin complex due to higher rates, partially offset by favorable differences between actual and estimated tax payments related to the 2021 fiscal year. Depreciation and amortization expense Depreciation and amortization expense decreased by $9.6 million compared to the three months ended December 31, 2021, primarily due to decreases of $5.0 million and $4.8 million at the Hilight system and the MGR assets, respectively, due to revisions in cost estimates related to asset retirement obligations made in the fourth quarter of 2021. Depreciation and amortization expense increased by $4.0 million compared to the three months ended March 31, 2021, primarily due to an increase of $3.2 million at a Wyoming asset primarily as a result of a change in estimate for asset retirement obligations in the comparative prior period. Long-lived asset and other impairment expense Long - lived asset and other impairment expense for the three months ended March 31, 2021, was primarily due to $13.5 million of impairments at the DJ Basin complex due to cancellation of projects. For further information on Long - lived asset and other impairment expense, see Note 7—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 44 Table of Contents Interest Expense Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Long - term and short - term debt $ (83,428) $ (87,448) (5) % $ (95,722) (13) % Finance lease liabilities (42) (53) (21) % (298) (86) % Commitment fees and amortization of debt-related costs (3,032) (3,041) — % (3,338) (9) % Capitalized interest 1,047 1,070 (2) % 865 21 % Interest expense $ (85,455) $ (89,472) (4) % $ (98,493) (13) % Interest expense Interest expense decreased by $4.0 million compared to the three months ended December 31, 2021, primarily due to decreases of $3.8 million for credit-rating related interest rate changes on the Fixed-Rate Senior Notes and Floating-Rate Senior Notes. Interest expense decreased by $13.0 million compared to the three months ended March 31, 2021, primarily due to decreases of (i) $4.1 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 on March 1, 2021, (ii) $4.1 million due to credit-rating related interest rate changes and lower outstanding balances on the 3.100% Senior Notes due 2025 and Floating-Rate Senior Notes, (iii) $2.3 million due to credit-rating related interest rate changes on the 4.050% Senior Notes due 2030 and 5.250% Senior Notes due 2050, and (iv) $2.1 million due to lower outstanding balances on the 3.950% Senior Notes due 2025, 4.000% Senior Notes due 2022, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021. See Liquidity and Capital Resources—Debt and credit facilities within this Item 2. Income Tax Expense (Benefit) Three Months Ended thousands except percentages March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Income (loss) before income taxes $ 319,475 $ 236,639 35 % $ 192,347 66 % Income tax expense (benefit) 1,805 (14,210) (113) % 1,112 62 % Effective tax rate 1 % NM 1 % We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. For the three months ended March 31, 2022 and 2021, the variance from the federal statutory rate was primarily due to our Texas margin tax liability. For the three months 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. 45 Table of Contents KEY PERFORMANCE METRICS Three Months Ended thousands except percentages and per-unit amounts March 31, 2022 December 31, 2021 Inc/ (Dec) March 31, 2021 Inc/ (Dec) Adjusted gross margin for natural - gas assets $ 488,909 $ 488,220 — % $ 432,389 13 % Adjusted gross margin for crude - oil and NGLs assets 148,247 114,733 29 % 133,145 11 % Adjusted gross margin for produced - water assets 67,594 67,296 — % 49,090 38 % Adjusted gross margin 704,750 670,249 5 % 614,624 15 % Per - Mcf Adjusted gross margin for natural - gas assets (1) 1.34 1.26 6 % 1.19 13 % Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (2) 2.44 1.78 37 % 2.45 — % Per - Bbl Adjusted gross margin for produced - water assets (3) 1.00 0.92 9 % 0.92 9 % Adjusted EBITDA 539,050 480,874 12 % 443,110 22 % Free cash flow 200,342 576,499 (65) % 211,822 (5) % _________________________________________________________________________________________ (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 increased by $34.5 million compared to the three months ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment that decreased revenue during the fourth quarter of 2021 at the DJ Basin oil system, partially offset by decreased throughput, (ii) the treatment of lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system that was terminated effective December 31, 2021, partially offset by decreased throughput, and (iii) strong plant performance and contract mix at the West Texas and DJ Basin complexes leading to increased product recoveries and higher commodity prices, partially offset by lower throughput. These increases were offset partially by (i) an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2021 at the Springfield system and (ii) a decrease in distributions from Whitethorn LLC. Adjusted gross margin increased by $90.1 million compared to the three months ended March 31, 2021, primarily due to (i) increased throughput, partially offset by a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2022, at the West Texas complex, (ii) increased throughput at the DBM water systems and DBM oil system, and (iii) a higher average gathering and processing fee and increased deficiency fees on certain contracts at the DJ Basin complex. These increases were offset partially by a decrease in distributions from Whitethorn LLC. 46 Table of Contents Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.08 compared to the three months ended December 31, 2021, primarily due to strong plant performance and contract mix at the West Texas and DJ Basin complexes leading to increased product recoveries, coupled with higher commodity prices and lower throughput. Per - Mcf Adjusted gross margin for natural - gas assets increased by $0.15 compared to the three months ended March 31, 2021, primarily due to increased throughput at the West Texas complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.66 compared to the three months ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment that decreased revenue during the fourth quarter of 2021 at the DJ Basin oil system and (ii) the treatment of lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system that was terminated effective December 31, 2021. These increases were offset partially by a decrease in distributions from Whitethorn LLC. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets decreased by $0.01 compared to the three months ended March 31, 2021, primarily due to a decrease in distributions from Whitethorn LLC and Saddlehorn. These decreases were offset partially by increased throughput at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets Per - Bbl Adjusted gross margin for produced - water assets increased by $0.08 compared to the three months ended December 31, 2021 and March 31, 2021, primarily due to deficiency fees recorded in the first quarter of 2022. Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following: • our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis; • the ability of our assets to generate cash flow to make distributions; and • the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. Adjusted EBITDA increased by $58.2 million compared to the three months ended December 31, 2021, primarily due to (i) a $39.1 million increase in total revenues and other, (ii) an $18.1 million decrease in operation and maintenance expenses, and (iii) a $7.9 million decrease in general and administrative expenses excluding non - cash equity - based compensation expense. These amounts were offset partially by a $4.3 million decrease in distributions from equity investments. Adjusted EBITDA increased by $95.9 million compared to the three months ended March 31, 2021, primarily due to (i) an $83.3 million increase in total revenues and other, (ii) a $16.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), and (iii) an $11.4 million decrease in operation and maintenance expenses. These amounts were offset partially by (i) a $5.4 million decrease in distributions from equity investments, (ii) a $4.1 million increase in property taxes, and (iii) a $2.5 million increase in general and administrative expenses excluding non - cash equity - based compensation expense. 47 Table of Contents 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 decreased by $376.2 million compared to the three months ended December 31, 2021, primarily due to a decrease of $385.4 million in net cash provided by operating activities related to working capital fluctuations and timing, partially offset by a decrease of $11.9 million in capital expenditures. Free cash flow decreased by $11.5 million compared to the three months ended March 31, 2021, primarily due to (i) an increase of $22.2 million in capital expenditures, (ii) a $2.2 million decrease in distributions from equity investments in excess of cumulative earnings, and (iii) an increase of $2.0 million in contributions to equity investments. These amounts were offset partially by an increase of $14.9 million in net cash provided by operating activities. See Capital Expenditures and Historical Cash Flow within this Item 2 for further information. 48 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 that is most directly comparable to Adjusted gross margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA. The GAAP measure that is most directly comparable to Free cash flow is net cash provided by operating activities. Our non - GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted gross margin, Adjusted EBITDA, and Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures. Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results. The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free cash flow: Three Months Ended thousands March 31, 2022 December 31, 2021 March 31, 2021 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 758,297 $ 719,210 $ 674,974 Less: Cost of product 72,848 72,040 88,969 Depreciation and amortization 134,582 144,225 130,553 Gross margin 550,867 502,945 455,452 Add: Distributions from equity investments 55,795 60,054 61,189 Depreciation and amortization 134,582 144,225 130,553 Less: Reimbursed electricity-related charges recorded as revenues 18,404 19,783 17,312 Adjusted gross margin attributable to noncontrolling interests (1) 18,090 17,192 15,258 Adjusted gross margin $ 704,750 $ 670,249 $ 614,624 Adjusted gross margin for natural - gas assets $ 488,909 $ 488,220 $ 432,389 Adjusted gross margin for crude - oil and NGLs assets 148,247 114,733 133,145 Adjusted gross margin for produced - water assets 67,594 67,296 49,090 _________________________________________________________________________________________ (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. 49 Table of Contents Three Months Ended thousands March 31, 2022 December 31, 2021 March 31, 2021 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 317,670 $ 250,849 $ 191,235 Add: Distributions from equity investments 55,795 60,054 61,189 Non - cash equity - based compensation expense 7,743 6,842 6,734 Interest expense 85,455 89,472 98,493 Income tax expense 1,805 — 1,112 Depreciation and amortization 134,582 144,225 130,553 Impairments — 1,345 14,866 Other expense — 216 1,218 Less: Gain (loss) on divestiture and other, net 370 (234) (583) Gain (loss) on early extinguishment of debt — — (289) Equity income, net – related parties 49,607 45,308 52,165 Other income 106 392 — Income tax benefit — 14,210 — Adjusted EBITDA attributable to noncontrolling interests (1) 13,917 12,453 10,997 Adjusted EBITDA $ 539,050 $ 480,874 $ 443,110 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 276,458 $ 661,858 $ 261,550 Interest (income) expense, net 85,455 89,472 98,493 Accretion and amortization of long - term obligations, net (1,782) (1,762) (2,088) Current income tax expense (benefit) 673 (2,165) 555 Other (income) expense, net (106) (390) 1,207 Distributions from equity investments in excess of cumulative earnings – related parties 9,925 11,310 12,141 Changes in assets and liabilities: Accounts receivable, net 165,134 (147,139) 30,182 Accounts and imbalance payables and accrued liabilities, net 14,292 (58,392) 16,467 Other items, net 2,918 (59,465) 35,600 Adjusted EBITDA attributable to noncontrolling interests (1) (13,917) (12,453) (10,997) Adjusted EBITDA $ 539,050 $ 480,874 $ 443,110 Cash flow information Net cash provided by operating activities $ 276,458 $ 661,858 $ 261,550 Net cash used in investing activities (71,617) (70,251) (46,472) Net cash provided by (used in) financing activities (158,591) (489,470) (603,624) _________________________________________________________________________________________ (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. 50 Table of Contents Three Months Ended thousands March 31, 2022 December 31, 2021 March 31, 2021 Reconciliation of Net cash provided by operating activities to Free cash flow Net cash provided by operating activities $ 276,458 $ 661,858 $ 261,550 Less: Capital expenditures 83,971 95,917 61,783 Contributions to equity investments – related parties 2,070 752 86 Add: Distributions from equity investments in excess of cumulative earnings – related parties 9,925 11,310 12,141 Free cash flow $ 200,342 $ 576,499 $ 211,822 Cash flow information Net cash provided by operating activities $ 276,458 $ 661,858 $ 261,550 Net cash used in investing activities (71,617) (70,251) (46,472) Net cash provided by (used in) financing activities (158,591) (489,470) (603,624) 51 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 March 31, 2022, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short - term working capital requirements and long - term capital - expenditure and debt-service requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board on a quarterly basis. We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions. However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to 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) 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 first quarter of 2022 of $0.50000 per unit, or $206.2 million in the aggregate. The cash distribution is payable on May 13, 2022, to our unitholders of record at the close of business on May 2, 2022. 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. During the three months ended March 31, 2022, we repurchased 225,355 common units on the open market for an aggregate purchase price of $5.1 million. The units were canceled immediately upon receipt. As of March 31, 2022, we had an authorized amount of $994.9 million remaining under the program. For the year ended December 31, 2022, capital expenditures are expected to range between $550.0 million to $600.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta), representing a $150.0 million increase to the midpoint of our previously announced guidance. This updated guidance range includes capital expenditures attributable to a portion of Mentone Train III, a new 300 MMcf/d cryogenic processing plant at our West Texas complex that was sanctioned in May 2022, and additional well connect and expansion capital to support accelerated producer activity in the Delaware Basin. 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 II, Item 1A of this Form 10-Q. 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 March 31, 2022, we had a $430.8 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 and the Floating-Rate Senior Notes being classified as short-term debt on the consolidated balance sheet as of March 31, 2022. As of March 31, 2022, there was $2.0 billion available for borrowing under the RCF. See Note 8—Selected Components of Working Capital and Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 52 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 include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels. Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Three Months Ended March 31, thousands 2022 2021 Capital expenditures (1) 83,971 61,783 Capital incurred (1) 85,553 59,565 _________________________________________________________________________________________ (1) For the three months ended March 31, 2022 and 2021, included $1.0 million and $0.9 million, respectively, of capitalized interest. Capital expenditures increased by $22.2 million for the three months ended March 31, 2022, primarily due to increases of (i) $29.7 million at the West Texas complex primarily attributable to facility expansion and pipeline projects, and (ii) $4.5 million at the DBM oil system primarily related to an increase in pipeline and well connection projects. These increases were offset partially by decreases of (i) $3.2 million at the DBM water systems primarily due to reduced construction of additional water - disposal facilities and gathering projects, and (ii) $2.8 million at the DJ Basin oil system primarily related to a decrease in pipeline projects. Historical cash flow . The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities: Three Months Ended March 31, thousands 2022 2021 Net cash provided by (used in): Operating activities $ 276,458 $ 261,550 Investing activities (71,617) (46,472) Financing activities (158,591) (603,624) Net increase (decrease) in cash and cash equivalents $ 46,250 $ (388,546) Operating activities . Net cash provided by operating activities increased for the three months ended March 31, 2022, primarily due to (i) higher cash operating income and (ii) lower interest expense. These increases were offset partially by (i) the impact of changes in assets and liabilities and (ii) lower distributions from equity investments. Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior periods. Investing activities . Net cash used in investing activities for the three months ended March 31, 2022, primarily included the following: • $84.0 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; • $2.1 million of capital contributions primarily paid to Red Bluff Express; • $9.9 million of distributions received from equity investments in excess of cumulative earnings; and • $4.1 million of decreases to materials and supplies inventory. 53 Table of Contents Net cash used in investing activities for the three months ended March 31, 2021, primarily included the following: • $61.8 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; • $12.1 million of distributions received from equity investments in excess of cumulative earnings; and • $3.3 million of decreases to materials and supplies inventory. Financing activities . Net cash used in financing activities for the three months ended March 31, 2022, primarily included the following: • $134.7 million of distributions paid to WES unitholders; • $7.1 million of decreases in outstanding checks; • $5.1 million of unit repurchases; • $2.8 million of distributions paid to the noncontrolling interest owner of WES Operating; and • $2.0 million of distributions paid to the noncontrolling interest owner of Chipeta. Net cash used in financing activities for the three months ended March 31, 2021, primarily included the following: • $531.1 million to redeem the total principal amount outstanding of WES Operating’s 5.375% Senior Notes due 2021 and repay borrowings under the RCF; • $131.3 million of distributions paid to WES unitholders; • $22.0 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020; • $16.2 million of unit repurchases; • $2.6 million of distributions paid to the noncontrolling interest owner of WES Operating; • $100.0 million of borrowings under the RCF, which were used for general partnership purposes; and • $1.6 million of contributions from related parties. 54 Table of Contents Debt and credit facilities. As of March 31, 2022, the carrying value of outstanding debt was $6.9 billion. See Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. WES Operating Senior Notes . In mid - January 2020, WES Operating issued the Fixed - Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and the Floating - Rate Senior Notes due 2023. Including the effects of the issuance prices, underwriting discounts, and interest - rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 3.790%, 4.671%, and 5.869%, respectively, at March 31, 2022. The interest rate on the Floating - Rate Senior Notes was 1.84% at March 31, 2022. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” As a result of this upgrade, annualized borrowing costs will decrease by $7.9 million. As of March 31, 2022, the 4.000% Senior Notes due 2022 and the Floating-Rate Senior Notes were classified as short-term debt on the consolidated balance sheet. Subsequent to March 31, 2022, WES Operating redeemed the 4.000% Senior Notes due 2022 at par value on April 1, 2022, pursuant to the optional redemption terms in WES Operating’s indenture. At March 31, 2022, WES Operating was in compliance with all covenants under the relevant governing indentures. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors. The amounts involved may be material. Revolving credit facility. 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 March 31, 2022, 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 March 31, 2022, the interest rate on any outstanding RCF borrowings was 1.95% and the facility - fee rate was 0.25%. At March 31, 2022, WES Operating was in compliance with all covenants under the RCF. The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related - party transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most - recent four - consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270 - day period immediately following certain acquisitions. As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited. Finance lease liabilities. During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles. As of March 31, 2022, we have future finance-lease payments of $2.7 million for the remainder of 2022 and a total of $1.6 million in years thereafter. 55 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 5—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 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: Three Months Ended thousands March 31, 2022 December 31, 2021 March 31, 2021 Net income (loss) attributable to WES $ 308,717 $ 243,517 $ 185,791 Limited partner interests in WES Operating not held by WES (1) 6,317 4,986 3,811 General and administrative expenses (2) 741 726 886 Other income (expense), net (3) (2) (3) Income taxes — 6 — Net income (loss) attributable to WES Operating $ 315,772 $ 249,233 $ 190,485 _________________________________________________________________________________________ (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 for all periods presented. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. 56 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: Three Months Ended March 31, thousands 2022 2021 WES net cash provided by operating activities $ 276,458 $ 261,550 General and administrative expenses (1) 741 886 Non - cash equity - based compensation expense (131) 7,302 Changes in working capital (6,948) (8,067) Other income (expense), net (3) (3) WES Operating net cash provided by operating activities $ 270,117 $ 261,668 WES net cash provided by (used in) financing activities $ (158,591) $ (603,624) Distributions to WES unitholders (2) 134,749 131,265 Distributions to WES from WES Operating (3) (137,412) (124,919) Increase (decrease) in outstanding checks 135 (192) Unit repurchases 5,149 16,241 Other 6,085 — WES Operating net cash provided by (used in) financing activities $ (149,885) $ (581,229) _________________________________________________________________________________________ (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 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. (3) Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q . Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta. See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 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 3—Partnership Distributions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q . 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. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2021. 57 Table of Contents