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. Discussion of 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com. The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2023 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). 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 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, 2023, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems (1) 18 2 3 1 Treating facilities 38 3 — — Natural - gas processing plants/trains 24 3 — 3 NGLs pipelines 3 — — 5 Natural - gas pipelines 6 — — 1 Crude - oil pipelines 3 1 — 3 _________________________________________________________________________________________ (1) Includes the DBM water systems. Significant financial and operational events during the year ended December 31, 2023, included the following: • On October 13, 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments). See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information. • WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information. • WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Net proceeds from this offering were used to repay borrowings under the RCF and for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information. 57 Table of Contents • WES Operating redeemed the $213.1 million total principal amount outstanding of the Floating-Rate Senior Notes due 2023 at par value with cash on hand. • WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases. • In November 2023, WES operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion. See Liquidity and Capital Resources within this Item 7 for additional information. • Our fourth - quarter 2023 per - unit distribution is unchanged from the third-quarter 2023 per-unit distribution of $0.575. • The Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance. This Enhanced Distribution was paid, along with our regular first-quarter 2023 distribution, on May 15, 2023, to our unitholders of record at the close of business on May 1, 2023. • We repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. • Natural - gas throughput attributable to WES totaled 4,432 MMcf/d for the year ended December 31, 2023, representing a 5% increase compared to the year ended December 31, 2022. • Crude - oil and NGLs throughput attributable to WES totaled 652 MBbls/d for the year ended December 31, 2023, representing a 4% decrease compared to the year ended December 31, 2022. • Produced - water throughput attributable to WES totaled 1,009 MBbls/d for the year ended December 31, 2023, representing a 21% increase compared to the year ended December 31, 2022. • Gross margin was $2,341.2 million for the year ended December 31, 2023, representing a 4% increase compared to the year ended December 31, 2022. See Reconciliation of Non-GAAP Financial Measures within this Item 7. • Adjusted gross margin for natural - gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.28 per Mcf for the year ended December 31, 2023, representing a 3% decrease compared to the year ended December 31, 2022. • Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.48 per Bbl for the year ended December 31, 2023, representing a 1% increase compared to the year ended December 31, 2022. • Adjusted gross margin for produced - water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.83 per Bbl for the year ended December 31, 2023, representing a 12% decrease compared to the year ended December 31, 2022. 58 Table of Contents The following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2023 2022 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,635 1,470 11 % DJ Basin 1,322 1,331 (1) % Powder River Basin 120 33 NM Equity investments 466 483 (4) % Other 1,050 1,049 — % Total throughput for natural - gas assets 4,593 4,366 5 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 214 198 8 % DJ Basin 71 82 (13) % Powder River Basin 5 — 100 % Equity investments 333 373 (11) % Other 42 37 14 % Total throughput for crude - oil and NGLs assets 665 690 (4) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,029 853 21 % Total throughput for produced - water assets 1,029 853 21 % _________________________________________________________________________________________ NM — Not meaningful 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, 2023, our West Texas and DJ Basin assets provided (i) 53% and 34%, respectively, of Total revenues and other, (ii) 40% and 32%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 65% and 21%, 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, 2023, 59% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts. 59 Table of Contents For the year ended December 31, 2023, 95% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under certain of our processing agreements. We also have indirect exposure to commodity-price risk in that the relatively volatile commodity-price environment has caused and may continue to cause current or potential customers to alter drilling or production schedules in certain areas, which could cause variability in the volumes of hydrocarbons available to our systems. We also bear limited commodity-price risk through the settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K. HOW WE EVALUATE OUR OPERATIONS Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7). Throughput . Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities. Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors. Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services. General and administrative expenses . To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget. Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures associated with growth and maintenance projects is closely monitored. Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved. 60 Table of Contents 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. Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. In addition, certain of our natural-gas processing agreements provide our producer customers with the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows. See Risk Factors under Part I, Item 1A of this Form 10-K. Acquisitions and divestitures. In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF. For purposes of the discussion included in Results of Operations , the Powder River Basin complex includes our previously owned Hilight system and the assets acquired from Meritage. In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. Total proceeds were received during the fourth quarter of 2022, resulting in a net gain on sale of $109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million. Subsequent to the acquisition, (i) we are the sole owner and operator of the asset, (ii) Ranch Westex is no longer accounted for under the equity method of accounting, and (iii) the Ranch Westex gas processing plant is included as part of the operations of the West Texas complex. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Impairments. We recognized long-lived asset and other impairments of $52.9 million and $20.6 million for the years ended December 31, 2023 and 2022, respectively. For a description of impairments recorded, see Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 61 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 2023 2022 Total revenues and other (1) $ 3,106,476 $ 3,251,721 Equity income, net – related parties 152,959 183,483 Total operating expenses (1) 1,869,770 1,950,992 Gain (loss) on divestiture and other, net (10,102) 103,676 Operating income (loss) 1,379,563 1,587,888 Interest expense (348,228) (333,939) Gain (loss) on early extinguishment of debt 15,378 91 Other income (expense), net 5,679 1,603 Income (loss) before income taxes 1,052,392 1,255,643 Income tax expense (benefit) 4,385 4,187 Net income (loss) 1,048,007 1,251,456 Net income (loss) attributable to noncontrolling interests 25,791 34,353 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,022,216 $ 1,217,103 _________________________________________________________________________________________ (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, 2023” refer to the comparison of the year ended December 31, 2023, to the year ended December 31, 2022. Discussion of 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations , which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com . 62 Table of Contents Throughput Year Ended December 31, 2023 2022 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 435 409 6 % Processing 3,692 3,474 6 % Equity investments (1) 466 483 (4) % Total throughput 4,593 4,366 5 % Throughput attributable to noncontrolling interests (2) 161 156 3 % Total throughput attributable to WES for natural - gas assets 4,432 4,210 5 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 332 317 5 % Equity investments (1) 333 373 (11) % Total throughput 665 690 (4) % Throughput attributable to noncontrolling interests (2) 13 14 (7) % Total throughput attributable to WES for crude - oil and NGLs assets 652 676 (4) % Throughput for produced-water assets (MBbls/d) Gathering and disposal 1,029 853 21 % Throughput attributable to noncontrolling interests (2) 20 17 18 % Total throughput attributable to WES for produced - water assets 1,009 836 21 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting. (2) Includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests. Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 222 MMcf/d for the year ended December 31, 2023, primarily due to (i) higher volumes at the West Texas complex due to increased production in the area, (ii) higher volumes at the Powder River Basin complex as a result of the Meritage acquisition, (iii) higher volumes at the Springfield gas-gathering system due to new third-party production, (iv) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (v) higher volumes at the MIGC system. These increases were offset partially by (i) lower volumes at the Granger complex and Marcellus Interest systems due to production declines in the surrounding areas, (ii) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition, and (iii) lower volumes at the Mi Vida plant. Crude-oil and NGLs assets Total throughput attributable to WES for crude - oil and NGLs assets decreased by 24 MBbls/d for the year ended December 31, 2023, primarily due to (i) lower volumes on the Cactus II pipeline, which was sold in the fourth quarter of 2022, and (ii) lower volumes at the DJ Basin oil system resulting from production declines in the area. These decreases were offset partially by (i) increased volumes on the Whitethorn and Saddlehorn pipelines, (ii) higher volumes at the DBM oil system resulting from increased production in the area, and (iii) higher volumes on the Thunder Creek NGL pipeline which was acquired as part of the Meritage acquisition. Produced-water assets Total throughput attributable to WES for produced - water assets increased by 173 MBbls/d for the year ended December 31, 2023, due to higher production and new third-party connections brought online during 2023. 63 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Service revenues – fee based $ 2,768,757 $ 2,602,053 6 % Service revenues – product based 191,727 249,692 (23) % Total service revenues $ 2,960,484 $ 2,851,745 4 % Service revenues – fee based Service revenues – fee based increased by $166.7 million for the year ended December 31, 2023, primarily due to increases of (i) $114.1 million at the West Texas complex as a result of increased throughput and electricity-related rates billed to customers, (ii) $42.6 million at the Powder River Basin complex as a result of increased throughput attributable to the acquisition of Meritage (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7), (iii) $22.7 million at the DJ Basin complex due to increased deficiency fees on demand volumes and electricity-related rates billed to customers, (iv) $20.8 million and $12.1 million at the DBM water and DBM oil systems, respectively, due to increased throughput, partially offset by decreased deficiency fees, and (v) $5.6 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 compared to 2022, partially offset by decreased throughput and deficiency fees. These increases were partially offset by decreases of (i) $17.5 million at the Springfield system primarily due to decreased demand-fee revenue and a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by increased throughput, (ii) $12.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, and (iii) $12.1 million at the Chipeta complex due to decreased deficiency fees. Service revenues – product based Service revenues – product based decreased by $58.0 million for the year ended December 31, 2023, primarily due to decreases of (i) $22.0 million at the West Texas complex due to decreased average prices and lower product-related electricity reimbursements from customers, (ii) $14.5 million and $6.1 million at the DJ Basin and Powder River Basin complexes, respectively, due to decreased average prices, and (iii) $9.2 million and $4.3 million at the Red Desert and Granger complexes, respectively, due to decreased average prices and volumes sold. Product Sales Year Ended December 31, thousands except percentages and per-unit amounts 2023 2022 Inc/ (Dec) Natural - gas sales $ 40,679 $ 129,187 (69) % NGLs sales 104,345 269,836 (61) % Total Product sales $ 145,024 $ 399,023 (64) % Per - unit gross average sales price: Natural gas (per Mcf) $ 1.66 $ 5.66 (71) % NGLs (per Bbl) 27.89 40.51 (31) % Natural-gas sales Natural - gas sales decreased by $88.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $72.8 million at the West Texas complex due to decreased average prices, partially offset by higher volumes sold and (ii) $17.8 million at the Red Desert complex due to decreased average prices. These decreases were partially offset by an increase of $7.7 million at the DJ Basin complex as a result of contract mix, partially offset by decreased volumes sold and average prices. 64 Table of Contents NGLs sales NGLs sales decreased by $165.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $94.7 million at the West Texas complex due to changes in contract mix and decreased average prices, (ii) $22.9 million, $10.0 million, and $3.6 million at the Chipeta, Granger, and Red Desert complexes, respectively, due to decreased average prices and volumes sold, (iii) $22.9 million at the DJ Basin complex due to decreased average prices, partially offset by increased volumes sold, and (iv) $7.5 million at the Brasada complex due to a contract expiration in the third quarter of 2022. Equity Income, Net – Related Parties Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Equity income, net – related parties $ 152,959 $ 183,483 (17) % Equity income, net – related parties decreased by $30.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.7 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7) and (ii) $9.1 million, $6.0 million, and $3.5 million at TEP, Mont Belvieu JV, and Whitethorn, respectively. Cost of Product and Operation and Maintenance Expenses Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Residue purchases $ 32,515 $ 173,104 (81) % NGLs purchases 211,468 320,739 (34) % Other (79,385) (72,943) (9) % Cost of product 164,598 420,900 (61) % Operation and maintenance 762,530 654,566 16 % Total Cost of product and Operation and maintenance expenses $ 927,128 $ 1,075,466 (14) % Residue purchases Residue purchases decreased by $140.6 million for the year ended December 31, 2023, primarily due to decreases of (i) $84.1 million at the West Texas complex attributable to changes in contract mix during 2022 and lower average prices, (ii) $19.3 million at the Chipeta complex due to decreased volumes purchased and lower average prices, and (iii) $15.7 million and $8.2 million at the Red Desert and DJ Basin complexes, respectively, primarily due to lower average prices. NGLs purchases NGLs purchases decreased by $109.3 million for the year ended December 31, 2023, primarily due to decreases of (i) $61.5 million and $30.7 million at the West Texas and DJ Basin complexes, respectively, attributable to lower average prices and (ii) $7.7 million at the Brasada complex due to a contract expiration in the third quarter of 2022. Other items Other items decreased by $6.4 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.5 million at the West Texas complex due to changes in imbalance positions, partially offset by higher offload costs, and (ii) $3.8 million and $2.9 million at the Red Desert complex and MIGC system, respectively, attributable to changes in imbalance positions. These decreases were partially offset by an increase of $16.9 million at the DJ Basin complex due to changes in imbalance positions. 65 Table of Contents Operation and maintenance expense Operation and maintenance expense increased by $108.0 million for the year ended December 31, 2023, primarily due to increases of (i) $35.8 million for equipment maintenance and repair expense, (ii) $27.7 million for salaries and wages costs, (iii) $11.8 million in utility expense, (iv) $9.6 million in land-related costs, (v) $8.9 million in higher equipment rental costs, (vi) $8.0 million in water-disposal costs, and (vii) $5.6 million attributable to higher contract labor and consulting expense. Other Operating Expenses Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) General and administrative $ 232,632 $ 194,017 20 % Property and other taxes 56,458 78,559 (28) % Depreciation and amortization 600,668 582,365 3 % Long - lived asset and other impairments 52,884 20,585 157 % Total other operating expenses $ 942,642 $ 875,526 8 % General and administrative expenses General and administrative expenses increased by $38.6 million for the year ended December 31, 2023, primarily due to increases of (i) $16.2 million in personnel costs, including costs related to the acquisition of Meritage, (ii) $9.8 million in information technology costs, and (iii) $7.0 million in consulting and legal costs. Property and other taxes Property and other taxes decreased by $22.1 million for the year ended December 31, 2023, primarily due to decreases in the ad valorem property tax accrual during 2023 related to the finalization of 2022 assessments at the DJ Basin complex. Depreciation and amortization expense Depreciation and amortization expense increased by $18.3 million for the year ended December 31, 2023, primarily due to increases of (i) $10.1 million and $7.3 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service, (ii) $9.9 million at the Powder River Basin complex associated with the acquisition of Meritage, and (iii) $7.2 million related to depreciation for capitalized information technology implementation costs. These increases were offset partially by a decrease of $13.0 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2022. Long-lived asset and other impairment expense Long - lived asset and other impairment expense for the year ended December 31, 2023, was primarily due to a $52.1 million impairment for assets located in the Rockies. Long - lived asset and other impairment expense for the year ended December 31, 2022, was primarily due to a $19.9 million other-than-temporary impairment of our investment in White Cliffs. For further information on Long - lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 66 Table of Contents Interest Expense Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Long - term and short - term debt $ (348,393) $ (326,949) 7 % Finance lease liabilities (1,083) (414) 162 % Commitment fees and amortization of debt-related costs (12,395) (12,212) 1 % Capitalized interest 13,643 5,636 142 % Interest expense $ (348,228) $ (333,939) 4 % Interest expense increased by $14.3 million for the year ended December 31, 2023, primarily due to increases of (i) $34.7 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, (ii) $10.0 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, and (iii) $3.0 million primarily due to borrowings on the commercial paper program that was established during the fourth quarter of 2023. These increases were offset partially by decreases of (i) $14.6 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, (ii) $8.0 million due to higher capitalized interest, (iii) $6.7 million due to the redemption of the total principal amount outstanding of the Floating-Rate Senior Notes due 2023 during the first quarter of 2023, and (iv) $5.1 million due to the redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 during the second quarter of 2022. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7. Other Income (Expense), Net Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Other income (expense), net $ 5,679 $ 1,603 NM Other income (expense), net increased by $4.1 million for the year ended December 31, 2023, primarily due to interest income earned resulting from higher interest rates and cash and cash equivalent balances throughout 2023, partially offset by interest recorded in 2023 related to a sales tax audit. Income Tax Expense (Benefit) We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. See Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 67 Table of Contents RECONCILIATION OF NON-GAAP FINANCIAL MEASURES Adjusted gross margin. We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity - related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product. We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers. Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following: • our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis; • the ability of our assets to generate cash flow to make distributions; and • the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities. Free cash flow. We define “Free cash flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free cash flow an appropriate metric for assessing capital discipline, cost efficiency, and balance - sheet strength. Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period. Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes. 68 Table of Contents Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted gross margin is gross margin. Net income (loss) and net cash provided by operating activities are the GAAP measures that are most directly comparable to Adjusted EBITDA. The GAAP measure that is most directly comparable to Free cash flow is net cash provided by operating activities. Our non - GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect gross margin, net income (loss), and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted gross margin, Adjusted EBITDA, and Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures. Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results. The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free cash flow: Year Ended December 31, thousands 2023 2022 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 3,106,476 $ 3,251,721 Less: Cost of product 164,598 420,900 Depreciation and amortization 600,668 582,365 Gross margin 2,341,210 2,248,456 Add: Distributions from equity investments 194,273 250,050 Depreciation and amortization 600,668 582,365 Less: Reimbursed electricity-related charges recorded as revenues 102,109 81,764 Adjusted gross margin attributable to noncontrolling interests (1) 70,195 73,632 Adjusted gross margin $ 2,963,847 $ 2,925,475 _________________________________________________________________________________________ (1) Includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 69 Table of Contents To facilitate investor and industry analysis, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets . Year Ended December 31, thousands except per-unit amounts 2023 2022 Gross margin Gross margin for natural - gas assets (1) $ 1,738,125 $ 1,676,732 Gross margin for crude - oil and NGLs assets (1) 368,444 346,406 Gross margin for produced - water assets (1) 259,541 245,274 Per - Mcf Gross margin for natural - gas assets (2) 1.04 1.05 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 1.52 1.38 Per - Bbl Gross margin for produced - water assets (2) 0.69 0.79 Adjusted gross margin Adjusted gross margin for natural - gas assets $ 2,067,528 $ 2,031,600 Adjusted gross margin for crude - oil and NGLs assets 589,091 607,769 Adjusted gross margin for produced - water assets 307,228 286,106 Per - Mcf Adjusted gross margin for natural - gas assets (3) 1.28 1.32 Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (3) 2.48 2.46 Per - Bbl Adjusted gross margin for produced - water assets (3) 0.83 0.94 _________________________________________________________________________________________ (1) Excludes corporate-level depreciation and amortization. (2) Average for period. Calculated as Gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) for natural - gas assets, crude - oil and NGLs assets, or produced - water assets. (3) Average for period. Calculated as Adjusted gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets. 70 Table of Contents Year Ended December 31, thousands 2023 2022 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,048,007 $ 1,251,456 Add: Distributions from equity investments 194,273 250,050 Non - cash equity - based compensation expense 32,005 27,783 Interest expense 348,228 333,939 Income tax expense 4,385 4,187 Depreciation and amortization 600,668 582,365 Impairments 52,884 20,585 Other expense 1,739 555 Less: Gain (loss) on divestiture and other, net (10,102) 103,676 Gain (loss) on early extinguishment of debt 15,378 91 Equity income, net – related parties 152,959 183,483 Other income 6,976 1,648 Adjusted EBITDA attributable to noncontrolling interests (1) 48,345 54,049 Adjusted EBITDA $ 2,068,633 $ 2,127,973 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Interest (income) expense, net 348,228 333,939 Accretion and amortization of long - term obligations, net (8,151) (7,142) Current income tax expense (benefit) 3,341 2,188 Other (income) expense, net (5,679) (1,603) Distributions from equity investments in excess of cumulative earnings – related parties 39,104 63,897 Changes in assets and liabilities: Accounts receivable, net 78,346 116,296 Accounts and imbalance payables and accrued liabilities, net 68,019 7,812 Other items, net (67,564) (34,791) Adjusted EBITDA attributable to noncontrolling interests (1) (48,345) (54,049) Adjusted EBITDA $ 2,068,633 $ 2,127,973 Cash flow information Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Net cash used in investing activities (1,607,291) (218,237) Net cash provided by (used in) financing activities (67,912) (1,398,532) _________________________________________________________________________________________ (1) Includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 71 Table of Contents Year Ended December 31, thousands 2023 2022 Reconciliation of Net cash provided by operating activities to Free cash flow Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Less: Capital expenditures 735,080 487,228 Contributions to equity investments – related parties 1,153 9,632 Add: Distributions from equity investments in excess of cumulative earnings – related parties 39,104 63,897 Free cash flow $ 964,205 $ 1,268,463 Cash flow information Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Net cash used in investing activities (1,607,291) (218,237) Net cash provided by (used in) financing activities (67,912) (1,398,532) Gross margin. Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenue s, Product Sales , Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense). Gross margin increased by $92.8 million for the year ended December 31, 2023, due to a $256.3 million decrease in cost of product. This amount was offset partially by (i) a $145.2 million decrease in total revenues and other and (ii) an $18.3 million increase in depreciation and amortization. Net income (loss). Refer to Operating Results within this Item 7 for a discussion of the primary components of Net income (loss) as compared to the prior periods. Net income (loss) decreased by $203.4 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $113.8 million decrease in gain (loss) on divestiture and other, net, (iii) a $30.5 million decrease in equity income, net – related parties, and (iv) a $14.3 million increase in interest expense. These amounts were offset partially by (i) an $81.2 million decrease in total operating expenses and (ii) a $15.3 million increase in gain (loss) on early extinguishment of debt. Net cash provided by operating activities. Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods. 72 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2023 2022 Inc/ (Dec) Adjusted gross margin $ 2,963,847 $ 2,925,475 1 % Per - Mcf Adjusted gross margin for natural - gas assets (1) 1.28 1.32 (3) % Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (1) 2.48 2.46 1 % Per - Bbl Adjusted gross margin for produced - water assets (1) 0.83 0.94 (12) % Adjusted EBITDA 2,068,633 2,127,973 (3) % Free cash flow 964,205 1,268,463 (24) % _________________________________________________________________________________________ (1) Average for period. Calculated as Adjusted gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets. Adjusted gross margin. Adjusted gross margin increased by $38.4 million for the year ended December 31, 2023, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput, partially offset by decreased deficiency fees at the DBM water systems. These increases were partially offset by (i) a decrease in distributions from Cactus II, which was sold in the fourth quarter of 2022, (ii) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue, partially offset by increased throughput at the Springfield system, (iii) decreased deficiency fees at the Chipeta complex, (iv) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, (v) a decrease in distributions from Ranch Westex, which was acquired in the third quarter of 2022 and is included in the West Texas complex subsequent to the acquisition, and (vi) decreased throughput at the Granger complex. Per - Mcf Adjusted gross margin for natural - gas assets decreased by $0.04 for the year ended December 31, 2023, primarily due to (i) a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022 and decreased demand-fee revenue at the Springfield system, and (ii) decreased deficiency fees at the Chipeta complex. These decreases were partially offset by (i) increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, and (ii) increased deficiency fees at the DJ Basin complex. Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.02 for the year ended December 31, 2023, primarily due to (i) decreases in throughput and distributions from Cactus II, which was sold in the fourth quarter of 2022 and had lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by decreased throughput and deficiency fees at the DJ Basin oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (iii) an increase in distributions from FRP. These increases were partially offset by decreases in distributions from Whitethorn LLC, Mont Belvieu JV, and Saddlehorn. Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.11 for the year ended December 31, 2023, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2023, and lower deficiency fee revenues. Adjusted EBITDA. Adjusted EBITDA decreased by $59.3 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $108.0 million increase in operation and maintenance expenses, (iii) a $55.8 million decrease in distributions from equity investments, and (iv) a $34.4 million increase in general and administrative expenses excluding non - cash equity - based compensation expense. These amounts were offset partially by (i) a $256.2 million decrease in cost of product (net of lower of cost or market inventory adjustments), and (ii) a $22.1 million decrease in property and other taxes. Free cash flow. Free cash flow decreased by $304.3 million for the year ended December 31, 2023, primarily due to (i) a $247.9 million increase in capital expenditures, (ii) a $40.1 million decrease in net cash provided by operating activities, and (iii) a $24.8 million decrease in distributions from equity investments in excess of cumulative earnings. These amounts were offset partially by an $8.5 million decrease in contributions to equity investments. 73 Table of Contents See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. GENERAL TRENDS AND OUTLOOK We expect our business to be affected by the below - described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results. Impact of producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude - oil, natural - gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. During 2020, oil and natural - gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19. In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine. For example, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude - oil daily settlement prices during 2022 ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022, and prices during the year ended December 31, 2023, ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023. Similar disruptions could occur as a consequence of the current conflict in the Middle East. The extent and duration of commodity - price volatility, and the associated direct and indirect impact on our business, cannot be predicted. To address the risks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility. Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can have a significant impact on the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise. Liquidity and access to capital markets. In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions. From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute. Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are becoming more numerous, more stringent, and more complex. These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells. In addition, in certain areas in which we operate, public protests of oil and gas operations are not uncommon. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets. 74 Table of Contents Impact of inflation and supply-chain disruptions. The U.S. economy has recently experienced significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine. More specifically, the continued bottlenecks and disruptions have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, which has increased our operating costs and capital expenditures. Increases in inflationary pressure could materially and negatively impact our financial results. 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. Short- and long-term interest rates can be volatile resulting in immediate changes to interest expense on RCF borrowings, commercial paper borrowings, and other floating-rate debt securities. Any future increases in interest rates likely will result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics. Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies. However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited. LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity, as of December 31, 2023, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, our commercial paper program, and potential issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short - term working capital requirements and long - term capital - expenditure and debt-service requirements. The amount of future distributions to unitholders will be determined by the Board on a quarterly basis. Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) within 55 days following each quarter’s end. 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. The Board declared a cash distribution to unitholders for the fourth quarter of 2023 of $0.575 per unit, or $223.4 million in the aggregate. The cash distribution was paid on February 13, 2024, to our unitholders of record at the close of business on February 1, 2024. To facilitate the distribution of available cash, during 2022 we adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the regular first-quarter distribution of the following year (beginning in 2023), in a target amount equal to Free cash flow generated in the prior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases. This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of our business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing-twelve-months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect. Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7. In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance, which was paid in conjunction with our regular first-quarter 2023 distribution on May 15, 2023. 75 Table of Contents In 2022, we announced a common-unit buyback program of up to $1.25 billion through December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the year ended December 31, 2023, we repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. The units were canceled immediately upon receipt. As of December 31, 2023, we had an authorized amount of $627.8 million remaining under the program. For the year ended December 31, 2024, capital expenditures are expected to range between $700.0 million to $850.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Total-year capital expenditures guidance includes capital expenditures attributable to (i) a portion of Mentone Train III, which is expected to be complete and in-service at the end of the first quarter of 2024, (ii) a portion of the North Loving plant, a new 250 MMcf/d cryogenic processing plant in the North Loving area of our West Texas complex that was sanctioned in May 2023, and (iii) additional expansion capital needed to support new commercial activity. Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or financing agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors and the amounts involved may be material. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. 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, 2023, we had a $311.6 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Our working capital deficit was primarily due to the outstanding commercial paper borrowings being classified as short-term debt on the consolidated balance sheet. As of December 31, 2023, there was $1.4 billion in effective borrowing capacity under the RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for our commercial paper program. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 76 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: Year Ended December 31, thousands 2023 2022 Acquisitions $ 877,746 $ 40,127 Capital expenditures (1) 735,080 487,228 Capital incurred (1) 752,338 534,342 _________________________________________________________________________________________ (1) For the years ended December 31, 2023 and 2022, included $13.6 million and $5.6 million, respectively, of capitalized interest. Acquisitions for the year ended December 31, 2023, include the acquisition of Meritage. Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex. See Items Affecting the Comparability of Our Financial Results within this Item 7. Capital expenditures increased by $247.9 million for the year ended December 31, 2023, primarily due to increases of (i) $130.4 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III and engineering and equipment milestone payments for the North Loving Plant, and pipeline projects, (ii) $55.0 million at the DBM water systems due to construction of additional water - disposal wells and facilities, pipeline build-out, and replacement projects, (iii) $39.0 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects, (iv) $10.0 million related to the acquisition of Meritage, (v) $9.9 million at the DJ Basin oil system due to an increase in pipeline projects, and (vi) $8.3 million at the DJ Basin complex due to an increase in well connection and pipeline projects. 77 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 2023 2022 Net cash provided by (used in): Operating activities $ 1,661,334 $ 1,701,426 Investing activities (1,607,291) (218,237) Financing activities (67,912) (1,398,532) Net increase (decrease) in cash and cash equivalents $ (13,869) $ 84,657 Operating activities . Net cash provided by operating activities decreased for the year ended December 31, 2023, primarily due to (i) lower distributions from equity investments, (ii) higher interest expense, and (iii) lower cash operating income. These decreases were partially offset by the impact of changes in assets and liabilities. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities . Net cash used in investing activities for the year ended December 31, 2023, primarily included the following: • $877.7 million of cash paid, net of cash received, for the acquisition of Meritage; • $735.1 million of capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system; • $32.3 million of increases to materials and supplies inventory; and • $39.1 million of distributions received from equity investments in excess of cumulative earnings. Net cash used in investing activities for the year ended December 31, 2022, primarily included the following: • $487.2 million of capital expenditures, primarily related to construction, expansion, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system; • $40.1 million of cash paid for the acquisition of the remaining 50% interest in Ranch Westex; • $9.6 million of capital contributions primarily paid to Red Bluff Express; • $9.5 million of increases to materials and supplies inventory; • $263.0 million in proceeds from the sale of our 15.00% interest in Cactus II; and • $63.9 million of distributions received from equity investments in excess of cumulative earnings. Financing activities . Net cash used in financing activities for the year ended December 31, 2023, primarily included the following: • $1,495.0 million of repayments of outstanding borrowings under the RCF; • $1,008.9 million of distributions paid to WES unitholders and noncontrolling interest owners; • $259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; • $213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value; 78 Table of Contents • $134.6 million of unit repurchases; • $1,120.0 million of borrowings under the RCF, which were used for general partnership purposes; • $740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes; • $609.9 million of net borrowings under the commercial paper program, which were used for general partnership purposes; and • $592.8 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes. Net cash used in financing activities for the year ended December 31, 2022, primarily included the following: • $1,015.0 million of repayments of outstanding borrowings under the RCF; • $735.8 million of distributions paid to WES unitholders; • $502.2 million to redeem the total principal amount outstanding of WES Operating’s 4.000% Senior Notes due 2022; • $487.6 million of unit repurchases; • $24.9 million of distributions paid to the noncontrolling interest owner of WES Operating; • $10.7 million of distributions paid to the noncontrolling interest owner of Chipeta; • $1,390.0 million of borrowings under the RCF, which were used for general partnership purposes and to redeem portions of certain of WES Operating’s senior notes; and • $2.2 million of increases in outstanding checks. Debt and credit facilities. As of December 31, 2023, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $346.3 million in 2024. In addition, we have no senior note borrowings due within the next year and, as of December 31, 2023, have $1.4 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for WES Operating’s commercial paper program. During the year ended December 31, 2023, WES Operating (i) completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029, (ii) completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033, (iii) entered into an amendment to our RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date, (iv) entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion (WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings), (v) purchased and retired $276.7 million of certain of its senior notes via open-market repurchases, and (vi) redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand. In May 2023, Fitch Ratings upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” WES Operating’s senior unsecured debt ratings are now investment grade at Standard and Poor’s, Moody’s Investors Services, and Fitch Ratings. As a result of the upgrade, annualized borrowing costs will decrease by $6.9 million on WES Operating’s senior notes that are subject to effective interest-rate adjustments from a change in credit rating. For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 79 Table of Contents Finance lease liabilities. WES has finance leases with third parties for equipment, vehicles, and an NGL pipeline in Wyoming. As of December 31, 2023, we have future finance-lease payments of $7.7 million for 2024 and a total of $35.0 million in years thereafter. Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in property, 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, 2023, we expect to incur asset retirement costs of $7.6 million in 2024 and a total of $359.2 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, 2023, we have future operating-lease payments of $11.6 million in 2024 and a total of $67.7 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Offload commitments. We have entered into offload agreements with third parties providing firm-processing capacity through 2025. As of December 31, 2023, we have future minimum payments under offload agreements totaling $7.7 million for 2024 and a total of $3.4 million in years thereafter. Pipeline commitments. We have entered into transportation contracts with volume commitments on multiple pipelines through 2033. As of December 31, 2023, we have estimated future minimum-volume-commitment fees totaling $11.3 million for 2024, and a total of $67.5 million in years thereafter. Credit risk . We bear credit risk through exposure to non - payment or non - performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non - payment or non - performance results from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our contractual rights to request adequate assurance of performance. We expect our exposure to the concentrated risk of non - payment or non - performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. 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. 80 Table of Contents ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below. Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2023 2022 2021 Net income (loss) attributable to WES $ 1,022,216 $ 1,217,103 $ 916,292 Limited partner interest in WES Operating not held by WES (1) 20,922 24,899 18,765 General and administrative expenses (2) 2,943 2,656 2,932 Other income (expense), net (275) (45) (11) Income taxes 6 7 9 Net income (loss) attributable to WES Operating $ 1,045,812 $ 1,244,620 $ 937,987 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2023 2022 2021 WES net cash provided by operating activities $ 1,661,334 $ 1,701,426 $ 1,766,852 General and administrative expenses (1) 2,943 2,656 2,932 Non - cash equity - based compensation expense (581) (570) 6,912 Changes in working capital (15,226) (9,341) (11,315) Other income (expense), net (275) (45) (11) Income taxes 6 7 9 WES Operating net cash provided by operating activities $ 1,648,201 $ 1,694,133 $ 1,765,379 WES net cash provided by (used in) financing activities $ (67,912) $ (1,398,532) $ (1,752,237) Distributions to WES unitholders (2) 978,430 735,755 533,758 Distributions to WES from WES Operating (3) (1,119,367) (1,219,635) (734,034) Increase (decrease) in outstanding checks (52) 103 (68) Unit repurchases 134,602 487,590 217,465 Other 15,472 9,326 4,336 WES Operating net cash provided by (used in) financing activities $ (58,827) $ (1,385,393) $ (1,730,780) _________________________________________________________________________________________ (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. 81 Table of Contents Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders in proportion to their share of limited partner interests in WES Operating. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. CRITICAL ACCOUNTING ESTIMATES The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee. For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in throughput forecasts or changes in future development plans by producers, to the extent they affect our operations, may trigger an impairment assessment. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. The primary assumptions used to estimate undiscounted future net cash flows include long-range customer throughput forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets. 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. 82 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 an other-than-temporary loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the carrying amount exceeds the estimated fair value, an impairment loss is measured as the excess of the carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted down to its estimated fair value with an offsetting charge to impairment expense. We recognized long-lived asset and other impairments of $52.9 million for the year ended December 31, 2023, and $20.6 million (which includes an other-than-temporary impairment expense of an equity investment) for the year ended December 31, 2022. See Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2023, 2022, and 2021. Fair value. Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Fair value estimates in business combination accounting. Business combination accounting requires that assets and liabilities be recorded at their estimated fair value in connection with the initial recognition of the transaction. Estimating the fair value of assets and liabilities in connection with business combination accounting requires management to make estimates, assumptions and judgments, and in some cases management may also utilize third-party specialists to assist and advise on those estimates. In order to estimate the fair value of acquired assets and assumed liabilities, we utilize widely accepted valuation techniques that include market and discounted cash flow approaches. These approaches utilize assumptions that include, but are not limited to, estimated future cash flows, discount rates applied to estimated future cash flows, and estimated asset replacement costs. While we believe we have made reasonable assumptions to estimate the fair value, these assumptions are inherently uncertain. The acquisition-date fair value recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. RECENT ACCOUNTING DEVELOPMENTS 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. 83 Table of Contents