Exxon Mobil Corp 10-K

ITEM 9A. CONTROLS AND PROCEDURES Management’s Evaluation of Disclosure Controls and Procedures As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2024. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Management’s Report on Internal Control over Financial Reporting Management, including the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2024. The Corporation excluded Pioneer from our assessment of internal control over financial reporting as of December 31, 2024, because it was acquired by the Corporation in a business combination during 2024. Total assets and total revenues of Pioneer, a wholly owned subsidiary, represent nineteen percent and four percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2024, as stated in their report included in the Financial Section of this report. Changes in Internal Control over Financial Reporting There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting. 28 ITEM 9B. OTHER INFORMATION During the three months ended December 31, 2024, none of the Company’s directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Reference is made to the section of this report titled “Information about our Executive Officers”. Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2025 annual meeting of shareholders (the “2025 Proxy Statement”): • The section entitled “Election of Directors”; • The portion entitled "Delinquent Section 16(a) Reports" of the section entitled "Director and Executive Officer Stock Ownership"; • The portions entitled “Director Qualifications”, “Director Nomination Process and Board Succession”, and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance”; and • The “Director Independence” portion, “Board Meetings and Annual Meeting Attendance” portion, the membership table of the portion entitled “Board Committees”, the "Nominating and Governance Committee" portion and the "Audit Committee" portion of the section entitled “Corporate Governance”. The Corporation has adopted an Insider Trading Policy governing the purchase, sale, and/or other dispositions of its securities by its directors, officers and employees, and the Corporation itself, that the Corporation believes is reasonably designed to promote compliance with insider trading laws, rules and regulations and the exchange listing standards applicable to the Corporation. A copy of the Corporation’s Insider Trading Policy is filed as Exhibit 19 to this report. ITEM 11. EXECUTIVE COMPENSATION Incorporated by reference to the sections entitled “Director Compensation”, “Compensation Committee Report”, “Compensation Discussion and Analysis”, “Executive Compensation Tables”, “Pay Ratio”, and "Pay Versus Performance" of the registrant’s 2025 Proxy Statement. 29 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required under Item 403 of Regulation S-K is incorporated by reference to the sections entitled “Certain Beneficial Owners” and “Director and Executive Officer Stock Ownership” of the registrant’s 2025 Proxy Statement. Equity Compensation Plan Information (a) (b) (c) Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans [Excluding Securities Reflected in Column (a)] Equity compensation plans approved by security holders 45,247,799 (1) — 56,689,904 (2)(3) Equity compensation plans not approved by security holders — — — Total 45,247,799 — 56,689,904 (1) The number of restricted stock units to be settled in shares. (2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 47,088,821 shares available for award under the 2003 Incentive Program, 238,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan, and 9,362,383 shares available for award under the Pioneer Natural Resources Company Amended and Restated 2006 Long Term Incentive Plan. (3) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Incorporated by reference to the portion entitled “Director Independence” of the section entitled “Corporate Governance” and the portion entitled “Related Person Transactions and Procedures” of the section entitled “Director and Executive Officer Stock Ownership” of the registrant’s 2025 Proxy Statement. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2025 Proxy Statement. PART IV ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES (a) (1) and (2) Financial Statements: See Table of Contents of the Financial Section of this report. (b) (3) Exhibits: See Index to Exhibits of this report. ITEM 16. FORM 10-K SUMMARY None. 30 FINANCIAL SECTION TABLE OF CONTENTS Business Profile 32 Financial Information 33 Frequently Used Terms 34 Management’s Discussion and Analysis of Financial Condition and Results of Operations Forward-Looking Statements 39 Overview 40 Business Environment 41 Business Results 47 Liquidity and Capital Resources 61 Capital and Exploration Expenditures 64 Taxes 66 Environmental Matters 66 Market Risks 67 Critical Accounting Estimates 68 Management’s Report on Internal Control over Financial Reporting 73 Report of Independent Registered Public Accounting Firm 74 Consolidated Financial Statements Statement of Income 77 Statement of Comprehensive Income 78 Balance Sheet 79 Statement of Cash Flows 80 Statement of Changes in Equity 81 Notes to Consolidated Financial Statements 1. Summary of Accounting Policies 82 2. Russia 86 3. Miscellaneous Financial Information 87 4. Other Comprehensive Income Information 88 5. Cash Flow Information 89 6. Additional Working Capital Information 89 7. Equity Company Information 90 8. Investments, Advances and Long-Term Receivables 92 9. Property, Plant and Equipment and Asset Retirement Obligations 92 10. Accounting for Suspended Exploratory Well Costs 94 11. Leases 95 12. Earnings Per Share 96 13. Financial Instruments and Derivatives 97 14. Long-Term Debt 98 15. Incentive Program 100 16. Litigation and Other Contingencies 101 17. Pension and Other Postretirement Benefits 102 18. Disclosures about Segments and Related Information 108 19. Income and Other Taxes 113 20. Divestment Activities 117 21. Mergers and Acquisitions 118 Supplemental Information on Oil and Gas Exploration and Production Activities 121 31 BUSINESS PROFILE Earnings (Loss) After Income Taxes Average Capital Employed (Non-GAAP) Return on Average Capital Employed (Non-GAAP) Capital and Exploration Expenditures Financial 2024 2023 2024 2023 2024 2023 2024 2023 (millions of dollars) (millions of dollars) (percent) (millions of dollars) Upstream United States 6,426 4,202 85,285 51,957 7.5 8.1 11,252 8,813 Non-U.S. 18,964 17,106 93,390 91,358 20.3 18.7 10,596 10,948 Total 25,390 21,308 178,675 143,315 14.2 14.9 21,848 19,761 Energy Products United States 2,099 6,123 13,190 12,540 15.9 48.8 756 1,195 Non-U.S. 1,934 6,019 21,135 20,010 9.2 30.1 1,610 1,580 Total 4,033 12,142 34,325 32,550 11.7 37.3 2,366 2,775 Chemical Products United States 1,627 1,626 14,277 14,702 11.4 11.1 739 751 Non-U.S. 950 11 14,760 13,859 6.4 0.1 1,332 1,962 Total 2,577 1,637 29,037 28,561 8.9 5.7 2,071 2,713 Specialty Products United States 1,576 1,536 2,035 2,148 77.4 71.5 145 63 Non-U.S. 1,476 1,178 6,183 6,366 23.9 18.5 270 391 Total 3,052 2,714 8,218 8,514 37.1 31.9 415 454 Corporate and Financing (1,372) (1,791) 27,847 30,500 — — 851 622 Corporate total 33,680 36,010 278,102 243,440 12.7 15.0 27,551 26,325 See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed. Due to rounding, numbers presented may not add up precisely to the totals indicated. Operating 2024 2023 2024 2023 Net liquids production (thousands of barrels daily) Refinery throughput (thousands of barrels daily) United States 1,248 803 United States 1,865 1,848 Non-U.S. 1,739 1,646 Non-U.S. 2,035 2,220 Total 2,987 2,449 Total 3,900 4,068 Natural gas production available for sale (millions of cubic feet daily) Energy Products sales (2) (thousands of barrels daily) United States 2,887 2,311 United States 2,722 2,633 Non-U.S. 5,191 5,423 Non-U.S. 2,696 2,828 Total 8,078 7,734 Total 5,418 5,461 Oil-equivalent production (1) (thousands of oil-equivalent barrels daily) 4,333 3,738 Chemical Products sales (2) (thousands of metric tons) United States 7,038 6,779 Non-U.S. 12,354 12,603 Total 19,392 19,382 Specialty Products sales (2) (thousands of metric tons) United States 1,922 1,962 Non-U.S. 5,745 5,635 Total 7,666 7,597 (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 32 FINANCIAL INFORMATION (millions of dollars, except where stated otherwise) 2024 2023 2022 Sales and other operating revenue 339,247 334,697 398,675 Net income (loss) attributable to ExxonMobil 33,680 36,010 55,740 Earnings (loss) per common share (dollars) 7.84 8.89 13.26 Earnings (loss) per common share – assuming dilution (dollars) 7.84 8.89 13.26 Earnings (loss) to average ExxonMobil share of equity (percent) 14.4 18.0 30.7 Working capital 21,683 31,293 28,586 Ratio of current assets to current liabilities (times) 1.31 1.48 1.41 Additions to property, plant and equipment (1) 109,332 29,038 18,338 Property, plant and equipment, less allowances 294,318 214,940 204,692 Total assets 453,475 376,317 369,067 Exploration expenses, including dry holes 826 751 1,025 Research and development costs 987 879 824 Long-term debt 36,755 37,483 40,559 Total debt 41,710 41,573 41,193 Debt to capital (percent) 13.4 16.4 16.9 Net debt to capital (percent) (2) 6.5 4.5 5.4 ExxonMobil share of equity at year-end 263,705 204,802 195,049 ExxonMobil share of equity per common share (dollars) 60.58 51.57 47.78 Weighted-average number of common shares outstanding (millions) 4,298 4,052 4,205 Number of regular employees at year-end (thousands) (3) 60.9 61.5 62.3 (1) Includes non-cash additions. See Note 21 for additions resulting from the Pioneer acquisition in 2024. (2) Net debt is total debt less cash and cash equivalents excluding restricted cash. Net debt to capital ratio is net debt divided by net debt plus total equity. Total debt is the sum of notes and loans payable and long-term debt, as reported in the Consolidated Balance Sheet. (3) Regular employees are defined as active executive, management, professional, technical, administrative, and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. 33 FREQUENTLY USED TERMS Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculations. Cash Flow from Operations and Asset Sales (Non-GAAP) Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from asset sales and returns of investments from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash both from operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions. Cash Flow from Operations and Asset Sales (millions of dollars) 2024 2023 2022 Net cash provided by operating activities 55,022 55,369 76,797 Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments 4,987 4,078 5,247 Cash flow from operations and asset sales (Non-GAAP) 60,009 59,447 82,044 Capital Employed (Non-GAAP) Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed. Capital Employed (millions of dollars) 2024 2023 2022 Business uses: asset and liability perspective Total assets 453,475 376,317 369,067 Less liabilities and noncontrolling interests share of assets and liabilities Total current liabilities excluding notes and loans payable (65,352) (61,226) (68,411) Total long-term liabilities excluding long-term debt (75,807) (60,980) (56,990) Noncontrolling interests share of assets and liabilities (8,069) (8,878) (9,205) Add ExxonMobil share of debt-financed equity company net assets 3,242 3,481 3,705 Total capital employed (Non-GAAP) 307,489 248,714 238,166 Total corporate sources: debt and equity perspective Notes and loans payable 4,955 4,090 634 Long-term debt 36,755 37,483 40,559 ExxonMobil share of equity 263,705 204,802 195,049 Less noncontrolling interests share of total debt (1,168) (1,142) (1,781) Add ExxonMobil share of equity company debt 3,242 3,481 3,705 Total capital employed (Non-GAAP) 307,489 248,714 238,166 34 FREQUENTLY USED TERMS Return on Average Capital Employed (Non-GAAP) Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in our capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions. Return on Average Capital Employed (millions of dollars) 2024 2023 2022 Net income (loss) attributable to ExxonMobil 33,680 36,010 55,740 Financing costs (after-tax) Gross third-party debt (1,106) (1,175) (1,213) ExxonMobil share of equity companies (196) (307) (198) All other financing costs – net (252) 931 276 Total financing costs (1,554) (551) (1,135) Earnings (loss) excluding financing costs (Non-GAAP) 35,234 36,561 56,875 Average capital employed (Non-GAAP) 278,102 243,440 228,404 Return on average capital employed – corporate total (Non-GAAP) 12.7% 15.0% 24.9% Selected Earnings Driver Definitions The updated earnings drivers introduced in the first quarter of 2024 provide additional visibility into our business results. The Company evaluates these drivers periodically to determine if any enhancements may provide helpful insights to the market. Listed below are descriptions of the earnings drivers: Advantaged Volume Growth. Represents earnings impacts from change in volume/mix from advantaged assets, advantaged projects, and high-value products. • Advantaged Assets (Advantaged growth projects) . Includes Permian (heritage Permian (1) and Pioneer), Guyana and LNG. • Advantaged Projects. Includes capital projects and programs of work that contribute to Energy, Chemical, and/or Specialty Products segments that drive integration of segments/businesses, increase yield of higher value products, or deliver higher than average returns. • High-Value Products. Includes performance products and lower-emission fuels. Performance products (performance chemicals, performance lubricants) refers to products that provide differentiated performance for multiple applications through enhanced properties versus commodity alternatives and bring significant additional value to customers and end-users. Lower-emission fuels refers to fuels with lower life cycle emissions than conventional transportation fuels for gasoline, diesel and jet transport. Base Volume. Represents all volume/mix drivers not included in Advantaged Volume Growth defined above. Structural Cost Savings. Represents after-tax earnings effects of Structural Cost Savings as defined on the next page, including cash operating expenses related to divestments that were previously in the volume/mix driver. Expenses. Represents all expenses otherwise not included in other earnings drivers. Timing Effects. Represents timing effects that are primarily related to unsettled derivatives (mark-to-market) and other earnings impacts driven by timing differences between the settlement of derivatives and their offsetting physical commodity realizations (due to LIFO inventory accounting). (1) Heritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024. 35 FREQUENTLY USED TERMS Structural Cost Savings (Non-GAAP) Structural cost savings describes decreases in cash opex excluding energy and production taxes as a result of operational efficiencies, workforce reductions, divestment-related reductions, and other cost-savings measures that are expected to be sustainable compared to 2019 levels. Relative to 2019, estimated cumulative structural cost savings totaled $12.1 billion. The total change between periods in expenses below will reflect both structural cost savings and other changes in spend, including market factors, such as inflation and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations, mergers and acquisitions, new business venture development, and early-stage projects. Estimates of cumulative annual structural cost savings may be revised depending on whether cost reductions realized in prior periods are determined to be sustainable compared to 2019 levels. Structural cost savings are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to understand the Corporation’s efforts to optimize spending through disciplined expense management. Calculation of Structural Cost Savings (billions of dollars) 2019 2024 Components of Operating Costs From ExxonMobil’s Consolidated Statement of Income (U.S. GAAP) Production and manufacturing expenses 36.8 39.6 Selling, general and administrative expenses 11.4 10.0 Depreciation and depletion (includes impairments) 19.0 23.4 Exploration expenses, including dry holes 1.3 0.8 Non-service pension and postretirement benefit expense 1.2 0.1 Subtotal 69.7 74.0 ExxonMobil's share of equity company expenses (Non-GAAP) 9.1 9.6 Total Adjusted Operating Costs (Non-GAAP) 78.8 83.6 Total Adjusted Operating Costs (Non-GAAP) 78.8 83.6 Less: Depreciation and depletion (includes impairments) 19.0 23.4 Non-service pension and postretirement benefit expense 1.2 0.1 Other adjustments (includes equity company depreciation and depletion) 3.6 3.7 Total Cash Operating Expenses (Cash Opex) (Non-GAAP) 55.0 56.4 Energy and production taxes (Non-GAAP) 11.0 13.9 Market Activity / Other Structural Savings Total Cash Operating Expenses (Cash Opex) excluding Energy and Production Taxes (Non-GAAP) 44.0 +4.0 +6.6 -12.1 42.5 Due to rounding, numbers presented may not add up precisely to the totals indicated. 36 FREQUENTLY USED TERMS Earnings (loss) excluding Identified Items (Non-GAAP) Earnings (loss) excluding Identified Items are earnings (loss) excluding individually significant non-operational events with, typically, an absolute corporate total earnings impact of at least $250 million in a given quarter. The earnings (loss) impact of an Identified Item for an individual segment in a given quarter may be less than $250 million when the item impacts several segments or several periods. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The Corporation believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Earnings (loss) excluding Identified Items is not meant to be viewed in isolation or as a substitute for net income (loss) attributable to ExxonMobil as prepared in accordance with U.S. GAAP. Upstream 2024 2023 2022 (millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 6,426 18,964 25,390 4,202 17,106 21,308 11,728 24,751 36,479 Impairments (360) (48) (408) (1,978) (686) (2,664) — (3,790) (3,790) Gain/(loss) on sale of assets — 385 385 305 — 305 299 587 886 Tax-related items — 238 238 184 (126) 58 — (1,415) (1,415) Other — — — — — — — 1,380 1,380 Identified Items (360) 575 215 (1,489) (812) (2,301) 299 (3,238) (2,939) Earnings (loss) excluding Identified Items (Non-GAAP) 6,786 18,389 25,175 5,691 17,918 23,609 11,429 27,989 39,418 Energy Products 2024 2023 2022 (millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 2,099 1,934 4,033 6,123 6,019 12,142 8,340 6,626 14,966 Impairments (34) (59) (93) — — — (58) (216) (274) Tax-related items — 172 172 192 (48) 144 — (410) (410) Identified Items (34) 113 79 192 (48) 144 (58) (626) (684) Earnings (loss) excluding Identified Items (Non-GAAP) 2,133 1,821 3,954 5,931 6,067 11,998 8,398 7,252 15,650 Chemical Products 2024 2023 2022 (millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 1,627 950 2,577 1,626 11 1,637 2,328 1,215 3,543 Impairments (43) (52) (95) (21) (273) (294) — — — Tax-related items — — — 53 — 53 — — — Other — — — — (147) (147) — — — Identified Items (43) (52) (95) 32 (420) (388) — — — Earnings (loss) excluding Identified Items (Non-GAAP) 1,670 1,002 2,672 1,594 431 2,025 2,328 1,215 3,543 Specialty Products 2024 2023 2022 (millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 1,576 1,476 3,052 1,536 1,178 2,714 1,190 1,225 2,415 Impairments (4) (8) (12) — (82) (82) — (40) (40) Tax-related items — (1) (1) 12 5 17 — — — Other — — — — (28) (28) — — — Identified Items (4) (9) (13) 12 (105) (93) — (40) (40) Earnings (loss) excluding Identified Items (Non-GAAP) 1,580 1,485 3,065 1,524 1,283 2,807 1,190 1,265 2,455 37 FREQUENTLY USED TERMS Corporate and Financing (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) (1,372) (1,791) (1,663) Impairments — — (98) Gain/(loss) on sale of assets 30 — — Tax-related items — 76 324 Other — — 76 Identified Items 30 76 302 Earnings (loss) excluding Identified Items (Non-GAAP) (1,402) (1,867) (1,965) Corporate Total (millions of dollars) 2024 2023 2022 Net income (loss) attributable to ExxonMobil (U.S. GAAP) 33,680 36,010 55,740 Impairments (608) (3,040) (4,202) Gain/(loss) on sale of assets 415 305 886 Tax-related items 409 348 (1,501) Other — (175) 1,456 Identified Items 216 (2,562) (3,361) Earnings (loss) excluding Identified Items (Non-GAAP) 33,464 38,572 59,101 References in this discussion to Corporate earnings (loss) mean net income (loss) attributable to ExxonMobil (U.S. GAAP) from the Consolidated Statement of Income. Unless otherwise indicated, references to earnings (loss), Upstream, Energy Products, Chemical Products, Specialty Products, and Corporate and Financing earnings (loss), and earnings (loss) per share are ExxonMobil's share after excluding amounts attributable to noncontrolling interests. Due to rounding, numbers presented may not add up precisely to the totals indicated. 38 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS Statements related to future events; projections; descriptions of strategic, operating, and financial plans and objectives; statements of future ambitions and plans; and other statements of future events or conditions are forward-looking statements. Similarly, discussion of roadmaps or future plans related to carbon capture, transportation and storage, lower-emission fuels, hydrogen, ammonia, direct air capture, Proxxima TM systems, carbon materials, lithium and other future plans to reduce emissions and emission intensity of ExxonMobil, its affiliates, and third parties are dependent on future market factors, such as continued technological progress, stable policy support and timely rule-making and permitting, and represent forward-looking statements. Actual future results, including financial and operating performance; earnings power; potential earnings, cash flow, dividends or shareholder returns, including the timing and amounts of share repurchases; total capital expenditures and mix, including allocations of capital to low carbon and other new investments; realization and maintenance of structural cost reductions and efficiency gains, including the ability to offset inflationary pressure; plans to reduce future emissions and emissions intensity, including ambitions to reach Scope 1 and Scope 2 net zero from operated assets by 2050, to reach Scope 1 and 2 net zero in heritage Permian Basin (1) unconventional operated assets by 2030, and in Pioneer Permian assets by 2035, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, and to reach near-zero methane emissions from operated assets and other methane initiatives to meet ExxonMobil’s emission reduction plans and goals, divestment and start-up plans, and associated project plans as well as technology advances, including the timing and outcome of projects to capture, transport and store CO2, produce hydrogen and ammonia, produce lower-emission fuels, produce Proxxima TM systems, produce carbon materials, produce lithium, and use plastic waste as feedstock for advanced recycling; timely granting of governmental permits and certifications; future debt levels and credit ratings; business and project plans, timing, costs, capacities and profitability; resource recoveries and production rates; and planned Denbury Inc. (Denbury) and Pioneer integrated benefits, could differ materially due to a number of factors. These include global or regional changes in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and other market factors; economic conditions and seasonal fluctuations that impact prices and differentials for our products; developments or changes in local, national, or international laws, regulations, taxes, trade sanctions, trade tariffs, or policies affecting our business, such as government policies supporting lower carbon and new market investment opportunities, the punitive European taxes on the oil and gas sector and unequal support for different technological methods of emissions reduction or evolving, ambiguous and unharmonized standards imposed by various jurisdictions related to sustainability and GHG reporting; variable impacts of trading activities on our margins and results each quarter; actions of co-venturers, competitors and commercial counterparties; the outcome of commercial negotiations, including final agreed terms and conditions; the outcome of competitive bidding and project awards; the ability to access debt markets on favorable terms or at all; the occurrence, pace, rate of recovery and effects of public health crises; adoption of regulatory incentives consistent with law; reservoir performance, including variability and timing factors applicable to unconventional resources and the success of new unconventional technologie s; the level, outcome, and timing of exploration and development projects and decisions to invest in future reserves and resources; timely completion of construction projects; final management approval of future projects and any changes in the scope, terms, costs or assumptions of such projects as approved; the actions of government or other actors against our core business activities and acquisitions, divestitures or financing opportunities; war, civil unrest, attacks against the Company or industry, and other geopolitical or security disturbances, including disruption of land or sea transportation routes; decoupling of economies, and disruptions in trade alliances and military alliances; expropriations, seizure, or capacity, insurance, shipping, import or export limitations imposed by governments or laws; opportunities for potential acquisitions, investments or divestments and satisfaction of applicable conditions to closing, including timely regulatory approvals; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies without impairing our competitive positioning; unforeseen technical or operating difficulties and unplanned maintenance; the development and competitiveness of alternative energy and emission reduction technologies; consumer preferences including willingness and ability to pay for reduced emission products; the results of research programs and the ability to bring new technologies to commercial scale on a cost-competitive basis; and other factors discussed under Item 1A . Forward-looking and other statements regarding environmental and other sustainability efforts and aspirations are not an indication that these statements are material to investors or require disclosure in our filing with the SEC or any other regulatory authority. In addition, historical, current, and forward-looking environmental and other sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making. Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply ExxonMobil views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not ExxonMobil, and their (1) H eritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024. 39 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS use by ExxonMobil is not an endorsement by ExxonMobil of their underlying assumptions, likelihood or probability. Investment decisions are made on the basis of ExxonMobil’s separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by ExxonMobil of any or all of the positions or activities of such organization. Actions needed to advance ExxonMobil’s 2030 greenhouse gas emission-reductions plans are incorporated into its medium-term business plans, which are updated annually. The reference case for planning beyond 2030 is based on the Company’s Global Outlook (Outlook) research and publication. The Outlook is reflective of the existing global policy environment and an assumption of increasing policy stringency and technology improvement to 2050. Current trends for policy stringency and development of lower-emission solutions are not yet on a pathway to achieve net-zero by 2050. As such, the Outlook does not project the degree of required future policy and technology advancement and deployment for the world, or ExxonMobil, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and ExxonMobil’s business plans will be updated accordingly. References to projects or opportunities may not reflect investment decisions made by ExxonMobil or its affiliates. Individual projects or opportunities may advance based on a number of factors, including availability of stable and supportive policy, permitting, technological advancement for cost-effective abatement, insights from the Company planning process, and alignment with our partners and other stakeholders. Capital investment guidance in lower-emission investments is based on our corporate plan; however, actual investment levels will be subject to the availability of the opportunity set, public policy support, and focused on returns. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. OVERVIEW The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission and other new business opportunities, including carbon capture and storage, hydrogen, lower-emission fuels, Proxxima TM systems, carbon materials, and lithium. ExxonMobil's reportable segments are Upstream, Energy Products, Chemical Products, and Specialty Products. Where applicable, ExxonMobil voluntarily discloses additional U.S., Non-U.S., and regional splits to help investors better understand the Company's operations. The Company is organized along three businesses – Upstream, Product Solutions, and Low Carbon Solutions, aligning along market-focused value chains. Product Solutions consists of Energy Products, Chemical Products, and Specialty Products. Low Carbon Solutions is included in Corporate and Financing as the business continues to mature through commercialization and deployment of technology. The businesses are supported by centralized service-delivery groups, including Global Projects, Technology and Engineering, Global Operations and Sustainability, Global Trading, Supply Chain, and Global Business Solutions. ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new supplies of reliable and affordable lower-emission energy and other critical products. The Company’s integrated business model, with significant investments in Upstream, Energy Products, Chemical Products, and Specialty Products segments and Low Carbon Solutions businesses, generally reduces the Corporation’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment decisions are grounded on fundamentals reflected in our long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities which target a low cost of supply to ensure long-term competitiveness. The annual Corporate Plan process establishes the economic assumptions used for evaluating investments and sets operating and capital objectives. The Global Outlook (Outlook), developed annually, is the foundation for the Corporate Plan assumptions. Price ranges for crude oil and natural gas, including price differentials, refinery and chemical margins, volumes, development and operating costs, including greenhouse gas emissions pricing, and foreign currency exchange rates are part of the Corporate Plan assumptions developed annually. Corporate Plan volume projections are based on individual field production profiles, which are also updated at least annually. Major investment opportunities are evaluated over a range of potential market conditions. All major investments are reappraised to ensure we learn from our decisions, and the development and execution of the project. Lessons learned are incorporated in future projects. 40 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS ENVIRONMENT Long-Term Business Outlook ExxonMobil’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends; the scale and variety of energy needs worldwide; capability, practicality, and affordability of energy alternatives, including lower-carbon solutions; greenhouse gas emission-reduction technologies; and relevant government policies. The Outlook considers these fundamentals to form the basis for the Company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the Company’s view of global energy demand and supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development. In addition, ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. Included in the range of these scenarios are the Intergovernmental Panel on Climate Change (IPCC) Likely Below 2°C scenarios and three scenarios from the International Energy Agency (IEA): IEA Stated Policies Scenario (STEPS), which reflects a sector-by-sector assessment of current policy in place or announced by governments; IEA Announced Pledges Scenario (APS), which reflects aspirational government targets met on time and in full; and IEA Net Zero Emissions by 2050 Scenario (NZE), which the IEA describes as extremely challenging, acknowledging that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed or changes in developed government policies, market conditions, and advances in technology that may influence the cost, pace, and potential availability of certain pathways. Scenarios that employ a full complement of technology options are likely to provide the most economically efficient pathways. Using our own experts and third-party sources, we monitor a variety of signposts that may indicate a potential shift in the energy transition. For example, the regional pace of the transition could be influenced by the cost of new technologies compared to existing or alternative energy sources. To effectively evaluate the pace of change, ExxonMobil uses many scenarios to help identify signposts that provide leading indicators of future developments and allow for timely adjustments to future versions of the Outlook. Developing countries projected to drive energy demand growth Primary energy - Quadrillion Btu Source: ExxonMobil 2024 Global Outlook By 2050, the world’s population is projected to be around 9.7 billion people, or nearly 2 billion more than in 2023. Coincident with this population increase, the Outlook projects worldwide economic growth to average approximately 2.5 percent per year, with economic output nearly doubling by 2050 compared to 2023. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by almost 15 percent from 2023 to 2050. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic Co-operation and Development (OECD)). By contrast, energy use in developed nations is expected to decline by more than 10 percent as efficiency improves. As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices as well as lower-emission products will continue to help significantly reduce energy consumption and CO2 emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2050, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs. Under our Outlook, global electricity demand is expected to increase more than 75 percent from 2023 to 2050, with developing countries likely to account for approximately 80 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal-fired generation is expected to decline substantially to approximately 15 percent of the world’s electricity in 2050, versus approximately 35 percent in 2023, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2023 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is expected to increase more than 450 percent, helping total renewables (including other sources, e.g., hydropower) to account for approximately 90 percent of the increase in electricity supplies through 2050. Total renewables are expected to reach over 50 percent of global electricity supplies by 2050. Natural gas and nuclear are expected to be about 20 percent and 10 percent, respectively, of global electricity supplies by 2050. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors, including the cost and availability of various energy supplies and policy developments. 41 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy for transportation - including cars, trucks, ships, trains, and airplanes - is expected to increase by about 25 percent from 2023 to 2050. Transportation energy demand is expected to account for about 60 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak by around 2025, and then decline to levels seen in the early-2000s by 2050, as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of approximately 65 percent. By 2050, light-duty vehicles are expected to account for around 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in small volumes. Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods will increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as well as the increasing shift toward cleaner forms of energy, such as electricity and natural gas, with coal declining. Demand for oil will continue to grow as a feedstock for industry. As populations grow and prosperity rises, more energy will be needed to power homes, offices, schools, shopping centers, hospitals, etc. Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use is expected to rise more than 65 percent between 2023 and 2050. Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2050, global demand for liquid fuels is projected to grow to approximately 110 million oil-equivalent barrels per day, an increase of about 10 percent from 2023. The non-OECD share of global liquid fuels demand is expected to increase to nearly 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by more than 25 percent. Much of the global liquid fuels demand today is met by crude production from conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of supply sources - including tight oil, deepwater, oil sands, natural gas liquids, and biofuels - are expected to grow to help meet rising demand. Timely investments will remain critical to meeting global needs with reliable and affordable supplies. Natural gas is a lower-emission, versatile, and practical fuel for a wide variety of applications. Global natural gas demand is expected to rise more than 20 percent from 2023 to 2050, with approximately 75 percent of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas - the natural gas found in shale and other tight rock formations - will help meet these needs. In total, about 35 percent of the growth in natural gas supplies is expected to come from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting around two-thirds of worldwide demand in 2050. LNG trade will expand significantly, meeting about 70 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific. 42 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Oil and natural gas projected to play a critical role in the global energy mix Primary energy - Quadrillion Btu Percent of primary energy Source: ExxonMobil 2024 Global Outlook Source: ExxonMobil 2024 Global Outlook * Electricity and hydrogen are secondary energies derived from the primary energies shown. **Includes biomass, biofuels, hydropower, and geothermal. The world’s energy mix is highly diverse and will remain so through 2050. Oil is expected to continue as the largest source of energy with its share remaining close to 30 percent in 2050. Coal and natural gas are the next largest sources of energy today, with the share of natural gas growing to more than 25 percent by 2050, while the share of coal falls to about half that of natural gas. Nuclear power is projected to grow, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is expected to exceed 20 percent of global energy by 2050, with other renewables (e.g., biomass, hydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind and solar is expected to increase rapidly, growing over 400 percent from 2023 to 2050, when they are projected to be nearly 12 percent of the world energy mix. Decarbonization of industrial activities will require a suite of nascent or future lower-carbon technologies and stable supporting policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower-emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Hydrogen will be a key enabler replacing traditional furnace fuel to decarbonize the industrial sector. Hydrogen and hydrogen-based fuels like ammonia are also expected to make inroads into commercial transportation as technology improves to lower its cost and policy develops to support the needed infrastructure development. Carbon capture and storage on its own, or in combination with hydrogen production, is among the few proven technologies that could enable CO2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining, and petrochemicals. 43 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Significant oil and natural gas investment needed to meet projected global demand Projected global oil supply and demand Million barrels per day Excludes biofuels; IEA STEPS, IEA APS, and IEA NZE Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2024 Global Outlook; IPCC Likely Below 2°C Average and Range Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used; decline rates based on 10-yr Compound Annual Growth Rate (CAGR) Projected global natural gas supply and demand Billion cubic feet per day IEA STEPS, IEA APS, and IEA NZE Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2024 Global Outlook; IPCC Likely Below 2°C Average and Range Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used; decline rates based on 10-yr CAGR Our Outlook projects that oil demand will remain above 100 million barrels per day to 2050. Even under the average of IPCC Likely Below 2°C scenarios, oil demand still comes to 66 million barrels per day in 2050 – about two thirds of current consumption. Our Outlook shows oil production declines at a rate of about 15 percent per year. At that rate, in the absence of continued investment, by 2030 oil supplies would fall from 100 million barrels per day to less than 30 million barrels, more than 70 million barrels per day short of what is needed to meet demand. Limiting investment to only existing fields would slow the decline to about 4 percent; however, this would still be well below the oil demand in the IEA APS and average of IPCC Likely Below 2°C scenarios. To meet projected demand, the Corporation anticipates that the world’s available oil and gas resource base will grow, not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2050 will be significant and would be needed to meet even rapidly declining demand for oil and gas envisioned in aggressive decarbonization scenarios. International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into account policies established to reduce energy-related greenhouse gas emissions in its long-term Outlook. The climate accord reached at the 2015 Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. Our Outlook reflects an environment with increasingly stringent climate policies and seeks to identify potential impacts of these climate-related government policies, which often target specific sectors. For purposes of the Outlook, a proxy cost on energy-related CO2 emissions is assumed, based on regional considerations and relative levels of economic development, and by 2050, reaches up to $150 per metric ton for OECD nations and up to $100 per metric ton for non-OECD nations. As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. The Corporation continues to monitor the updates to the Nationally Determined Contributions (NDCs) that are submitted by nations that are signatories to the Paris Agreement, as well as other policy developments in light of net-zero ambitions formulated by some nations. The information provided in the Outlook includes ExxonMobil’s internal estimates and projections based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency. 44 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Progress Reducing Emissions The Corporation’s strategy seeks to maximize the advantages of our scale, business integration, leading technology, execution excellence, and our people to build globally competitive businesses that lead industry in earnings and cash flow growth across a range of future scenarios. We strive to play a leading role, regardless of how an energy transition unfolds. Across our portfolio of opportunities, we retain investment flexibility to maximize shareholder value. With advancements in technology and clear, consistent, stable, and effective government policies, we aim to achieve net-zero Scope 1 and 2 greenhouse gas emissions in our operated assets by 2050. Our net-zero ambition is backed by a comprehensive approach centered on detailed emission-reduction roadmaps for our major operated assets that were completed in 2022. The roadmaps build on the Company’s 2030 emission-intensity reduction plans and, notably, include reaching net-zero Scope 1 and 2 emissions in our heritage Permian Basin (1) unconventional operated assets by 2030, and by 2035 for Pioneer assets. We continue to update the roadmaps, including to account for portfolio changes, to reflect technology and policy, and to account for the many potential pathways, and the pace of an energy transition. Compared to 2016 levels, our 2030 plans are expected to drive the following reductions: • 20-30 percent reduction in corporate-wide greenhouse gas intensity; • 70-80 percent reduction in corporate-wide methane intensity; • 40-50 percent reduction in upstream greenhouse gas intensity; and • 60-70 percent reduction in corporate-wide flaring intensity. Our emission-reduction plans and 2050 net-zero ambition cover Scope 1 and 2 emissions from assets we operate, which now include Pioneer and Denbury. The Corporation plans to continue to pursue advantaged growth opportunities and lower-emission investments. These investments are targeted at reducing emissions in the Company’s operations as well as reducing the emissions of other companies. At this early stage, stable and supportive policy remains critical to enable emissions reductions, advance technology, and drive scale to improve costs. ExxonMobil’s Low Carbon Solutions business is working with the Product Solutions and Upstream businesses to grow a pipeline of emission-reduction opportunities in carbon capture and storage, hydrogen, lower-emission fuels, Proxxima TM systems, and carbon materials, as well as lithium to supply the global battery and electric vehicle markets. Our customers, many governments, and strategic partners recognize our combination of experience, skills, and capabilities that have the potential to help reduce emissions for ourselves and others. For example, on the U.S. Gulf Coast, we see an opportunity to create a carbon capture and storage business that will enable industrial customers to reduce their emissions. The acquisition of Denbury expanded our capabilities in this area, providing ExxonMobil with the largest owned and operated network of CO2 pipelines in the United States, including more than 900 miles of pipelines and multiple CO2 storage sites near the largest industrial complexes on the Gulf Coast. Combining Denbury’s assets and our experience we have created the largest CO2 network in the world which gives us a unique ability to help customers in the region reduce their emissions at a lower cost and faster pace. A cost-efficient transportation and storage system has the potential to accelerate carbon capture and storage deployment for both ExxonMobil and our third-party customers. Stable policy support, along with technology advancements and the development of market-driven mechanisms, will continue to be important to the development and deployment of lower-emission solutions. (1) H eritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024. 45 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Recent Business Environment During 2024, the price of crude oil remained near the middle of the pre-COVID 10-year range (2010-2019), as markets remained balanced. Through the first nine months of the year, natural gas prices declined towards the middle of the 10-year range due to strong supply and lower demand. In the fourth quarter, natural gas prices increased on rising demand driven by colder weather in the U.S. and Europe. Refining margins declined in 2024 from high 2023 levels as increased supply from industry capacity additions outpaced record global demand and remain near the bottom of the 10-year range. Chemical margins improved slightly in 2024 but remained well below the 10-year range driven by over-supply, primarily in Asia. The general rate of inflation across major countries peaked in 2022, rising from already elevated levels in 2021, due to additional impacts on energy and other commodities from the Russia-Ukraine conflict. Inflation has trended down since 2023 as a result of aggressive monetary tightening by major central banks and slowing global economic growth. However, there has been significant variation on the pace of change across OECD and non-OECD countries. With inflation gradually approaching the official targets in the U.S. and Eurozone, the Federal Reserve and the European Central Bank began lowering interest rates in 2024. Meanwhile, China has been under persistent deflationary pressure since 2023. The Corporation closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. Organizational changes implemented over the past several years enabled the Corporation to capture $12.1 billion of structural cost savings (1) versus 2019, including $2.4 billion of savings during 2024, through increased operational efficiencies, workforce reductions, divestment-related reductions, and other cost-saving measures. The Company sees additional opportunities in areas such as supply chain efficiency, improved maintenance and turnarounds, modernized data management, centralization of activities, and simplified business processes. These savings are key drivers to further reduce our structural costs by $6 billion by 2030, thereby improving the earnings power of the Corporation. (1) Refer to Frequently Used Terms for definition of structural cost savings. Transportation of Kazakhstan Production The Corporation holds a 25 percent interest in Tengizchevroil, LLP (TCO), which operates the Tengiz and Korolev oil fields in Kazakhstan, and a 16.8 percent working interest in the Kashagan field in Kazakhstan. Oil production from those operations is exported primarily through the Caspian Pipeline Consortium (CPC), in which the Corporation holds a 7.5 percent interest. CPC traverses parts of Kazakhstan and Russia to tanker-loading facilities on the Russian coast of the Black Sea. In the event geopolitical issues escalate in the region, including ongoing military conflict, it is possible that the transportation of Kazakhstan oil through the CPC pipeline could be disrupted, curtailed, temporarily suspended, or otherwise restricted. In such a case, the Corporation could experience a loss of cash flows of uncertain duration from its operations in Kazakhstan. For reference, after-tax earnings related to the Corporation’s interests in Kazakhstan in 2024 were approximately $1.9 billion, and its share of combined oil and gas production was approximately 260 thousand oil-equivalent barrels per day. 46 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS RESULTS Upstream ExxonMobil has a diverse growth portfolio of exploration and development opportunities, which allows the Corporation to be selective in our investments, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s competitive strengths enable the Upstream’s business strategy, which is focused on developing an industry-leading portfolio underpinned by advantaged growth projects, applying ExxonMobil’s technology to enhance value and improve development efficiency, and leveraging the unique capabilities of the Company's global projects organization to deliver projects on time and in line with budgets. The Upstream capital program is focused on low cost-of-supply opportunities. ExxonMobil has a strong pipeline of development projects, including continued growth in Guyana and the Permian Basin, as well as LNG expansion opportunities in Qatar, Mozambique, Papua New Guinea, and the United States. As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix and in the type of opportunities from which volumes are produced. Based on the current investment plans, the proportion of oil-equivalent production from the Americas is generally expected to increase over the next several years. Currently about two thirds of the Corporation's global production comes from unconventional, deepwater, and LNG resources. This proportion is generally expected to grow. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, the impact of fiscal and commercial terms, asset sales, weather events, price effects on production sharing contracts, changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment, international trade patterns and relations, and other factors described in Item 1A . In 2024, crude and gas prices were within the pre-COVID 10-year historical range (2010-2019). ExxonMobil believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity, technology advances, consumer preference, and government policies. On the supply side, prices may be significantly impacted by political events, the actions of OPEC or OPEC+ and other large government resource owners, alternative energy sources, and other factors. Key Recent Events Guyana: Liza Destiny, Liza Unity and Prosperity floating production, storage and offloading (FPSO) vessels continued to produce above investment basis capacity in 2024. The combined gross production from the three operating vessels exceeded 615 thousand barrels of oil per day (kbd) in 2024 and exceeded 650 kbd in the fourth quarter of 2024. Yellowtail, Uaru and Whiptail, the fourth, fifth and sixth developments on the Stabroek Block, respectively, are progressing on schedule and each has an investment basis capacity of approximately 250 kbd. We announced plans for two additional developments and anticipate eight FPSO vessels will be in operation on the Stabroek Block by year-end 2030. We are working with the government of Guyana to secure regulatory approvals for the seventh project. Permian: ExxonMobil successfully closed the Pioneer Natural Resources Company (Pioneer) acquisition in May 2024, significantly increasing our Permian footprint. Total production volumes averaged approximately 1,185 thousand oil-equivalent barrels per day (koebd) in 2024, approximately 570 koebd higher than the previous year. ExxonMobil operations continue to deliver industry-leading capital efficiency and cost performance by leveraging scale, integration, and technology. Examples include deploying ExxonMobil cube design and proprietary proppant as well as leading capabilities and technology in drilling and completions. ExxonMobil remains on track to achieve industry-leading plans of Scope 1 and 2 net zero greenhouse gas emissions in the heritage Permian Basin (1) unconventional operated assets by 2030, and in Pioneer assets by 2035. ExxonMobil expects to roughly double production in the Permian Basin to approximately 2.3 Moebd by 2030. LNG: ExxonMobil continued work on LNG growth projects in 2024. Production commenced from two new gas wells in Papua New Guinea (PNG), marking completion of the Angore project and additional supply to support LNG export from the PNG LNG joint venture. In Mozambique, the Rovuma LNG project began the front-end engineering and design stage in 2024, in support of a final investment decision in 2026, to develop the Area 4 offshore gas resources. Construction continues on the Golden Pass LNG project with Train 1 mechanical completion and first LNG production expected at the end of 2025. (1) H eritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024. 47 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Upstream Financial Results (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) United States 6,426 4,202 11,728 Non-U.S. 18,964 17,106 24,751 Total 25,390 21,308 36,479 Identified Items (1) United States (360) (1,489) 299 Non-U.S. 575 (812) (3,238) Total 215 (2,301) (2,939) Earnings (loss) excluding Identified Items (1) (Non-GAAP) United States 6,786 5,691 11,429 Non-U.S. 18,389 17,918 27,989 Total 25,175 23,609 39,418 (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 2024 Upstream Earnings Driver Analysis (millions of dollars) Price – Price impacts decreased earnings by $1,250 million, driven by lower gas realizations. Advantaged Volume Growth – Higher volumes from advantaged projects increased earnings by $3,760 million, as a result of record production in Permian, driven by the Pioneer acquisition and growth in the heritage Permian (2) , and record production in Guyana driven by the Prosperity FPSO start-up. Base Volume – Divestments of non-strategic assets and entitlements decreased earnings by $820 million. Structural Cost Savings – Increased earnings by $830 million. Expenses – Higher expenses decreased earnings by $1,350 million, primarily from higher depreciation (non-cash). Other – All other items increased earnings by $120 million, mainly driven by favorable impacts from divestments, partially offset by unfavorable tax and foreign exchange impacts. Timing Effects – Less unfavorable timing effects from derivatives mark-to-market impacts increased earnings by $280 million. Identified Items (1) – 2023 $(2,301) million loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California; 2024 $215 million gain mainly due to Argentina divestment, partly offset by Nigeria divestment and U.S. impairment. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. (2) H eritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024. 48 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2023 Upstream Earnings Driver Analysis (millions of dollars) Price – Lower realizations decreased earnings by $14,290 million, reflecting lower gas prices and crude price moderation resulting from increased inventory levels. Advantaged Volume Growth – Higher volumes from advantaged assets increased earnings by $1,270 million, driven by Guyana and Permian production. . Base Volume – Base volumes decreased earnings by $800 million as a results of divestments, the Russia expropriation, and higher government-mandated curtailments. Structural Cost Savings – Increased earnings by $730 million. Expenses – Higher expenses decreased earnings by $650 million, primarily on increased activity and depreciation. Other – All other items increased earnings by $320 million, mainly driven by favorable foreign exchange effects. Timing Effects – Unfavorable timing effects from derivatives mark-to-market impacts decreased earnings by $2,390 million. Identified Items (1) – 2022 $(2,939) million loss mainly driven by the Russia expropriation $(2,185) million and impacts from additional European taxes $(1,415) million, partly offset by gains of $886 million on the sale of the Romania, U.S. Barnett Shale, and XTO Energy Canada assets; 2023 $(2,301) million loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 49 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Upstream Operational Results 2024 2023 2022 Net production of crude oil, natural gas liquids, bitumen and synthetic oil (thousands of barrels daily) United States 1,248 803 776 Canada/Other Americas 784 664 588 Europe 3 4 4 Africa 209 221 238 Asia 713 721 705 Australia/Oceania 30 36 43 Worldwide 2,987 2,449 2,354 Net natural gas production available for sale (millions of cubic feet daily) United States 2,887 2,311 2,551 Canada/Other Americas 101 96 148 Europe 352 414 667 Africa 152 125 71 Asia 3,322 3,490 3,418 Australia/Oceania 1,264 1,298 1,440 Worldwide 8,078 7,734 8,295 Oil-equivalent production (1) (thousands of oil-equivalent barrels daily) 4,333 3,738 3,737 (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. Upstream Additional Information (thousands of barrels daily) 2024 2023 Volumes Reconciliation (Oil-equivalent production) (1) Prior Year 3,738 3,737 Entitlements - Net Interest (13) (24) Entitlements - Price / Spend / Other (23) 56 Government Mandates 9 (28) Divestments (63) (114) Growth / Other 685 111 Current Year 4,333 3,738 (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. 2024 versus 2023 2024 production of 4.3 million oil-equivalent barrels per day increased 595 thousand barrels per day from 2023. Permian and Guyana production grew by 680 thousand oil-equivalent barrels per day, more than offsetting impacts from divestments and entitlements. Excluding the impacts from entitlements, divestments, and government-mandated curtailments, net production grew by 685 thousand oil-equivalent barrels per day. 2023 versus 2022 2023 production of 3.7 million oil-equivalent barrels per day is in line with 2022. Permian and Guyana production grew by more than 120 thousand oil-equivalent barrels per day, more than offsetting impacts from divestments. Excluding the impacts from entitlements, divestments, and higher government-mandated curtailments, net production grew by 111 thousand oil-equivalent barrels per day. 50 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Listed below are descriptions of ExxonMobil’s volumes reconciliation drivers, which are provided to facilitate understanding of the terms. Entitlements - Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to volume-determining drivers. These drivers consist of net interest changes specified in Production Sharing Contracts (PSCs), which typically occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon achieving pay-out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result of the termination or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices. Entitlements - Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes to non-operational volume-determining drivers. These drivers include changes in oil and gas prices or spending levels from one period to another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or market prices for oil and natural gas. Such drivers can also include other temporary changes in net interest as dictated by specific provisions in production agreements. Government Mandates are changes to ExxonMobil's sustainable production levels as a result of production limits or sanctions imposed by governments. Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity in a field or asset in exchange for financial or other economic consideration. Growth and Other drivers comprise all other operational and non-operational drivers not covered by the above definitions that may affect volumes attributable to ExxonMobil. Such drivers include, but are not limited to, production enhancements from project and work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline, and any fiscal or commercial terms that do not affect entitlements. Energy Products ExxonMobil's Energy Products is one of the largest, most integrated businesses of its kind among international oil companies, with significant representation across the entire fuels value chain, including refining, logistics, trading, and marketing. This segment includes the fuels and aromatics value chains, and catalysts and licensing. With the largest refining footprint among international oil companies, ExxonMobil’s Energy Products earnings are closely tied to industry refining margins. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials and the market prices for the products produced. Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g. New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather, and political considerations. While industry refining margins significantly impact Energy Products earnings, strong operational performance, product mix optimization, and disciplined cost control are also critical to strong financial performance. In 2024, refining margins decreased to the middle of the pre-COVID 10-year historical range (2010-2019) despite record demand, due to supply length. Refining margins are expected to remain volatile with changes in global factors, including geopolitical developments; demand growth; recession fears; inventory levels; and refining capacity utilization, additions and rationalizations. Key Recent Events Strathcona Renewable Diesel project: Progressed project with expected start-up in 2025 at Strathcona refinery to use low-carbon hydrogen, locally-sourced and grown feedstocks, and our proprietary catalyst to produce 20 thousand barrels of renewable diesel per day to help reduce greenhouse gas emissions. Fawley Hydrofiner project : Progressed project with expected start-up in 2025 at Fawley site to increase production of ultra-low sulfur diesel and reduce production of other products, including high-sulfur distillates. Fos-sur-Mer Refinery divestment: In October 2024, ExxonMobil divested the Fos refinery and select midstream assets in France. MiRO Refinery sale: In October 2023, ExxonMobil reached an agreement to sell its interest in the MiRO refinery located in Karlsruhe, Germany. The transaction is expected to close in 2025. 51 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy Products Financial Results (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) United States 2,099 6,123 8,340 Non-U.S. 1,934 6,019 6,626 Total 4,033 12,142 14,966 Identified Items (1) United States (34) 192 (58) Non-U.S. 113 (48) (626) Total 79 144 (684) Earnings (loss) excluding Identified Items (1) (Non-GAAP) United States 2,133 5,931 8,398 Non-U.S. 1,821 6,067 7,252 Total 3,954 11,998 15,650 (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. Due to rounding, numbers presented may not add up precisely to the totals indicated. 2024 Energy Products Earnings Driver Analysis (millions of dollars) Margin – Significantly weaker industry refining margins decreased earnings by $6,280 million. Margins declined from historically high levels as increased supply from industry capacity additions outpaced record global demand. Advantaged Volume Growth – Higher volumes from advantaged projects increased earnings by $140 million. Base Volume – Lower base volumes decreased earnings by $1,240 million, driven by scheduled maintenance and divestments. Structural Cost Savings – Increased earnings by $630 million. Expenses – Higher expenses related to scheduled turnarounds and maintenance, and advantaged project spend decreased earnings by $970 million. Other – All other items, mainly unfavorable tax and forex impacts, decreased earnings by $310 million. Timing Effects – Decreased earnings by $10 million. Identified Items (1) – 2023 $144 million gain driven by favorable tax effects partially offset by additional European taxes on the energy sector; 2024 $79 million gain. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 52 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2023 Energy Products Earnings Driver Analysis (millions of dollars) Margin – Margins decreased earnings by $3,510 million, mainly driven by industry refining margins which declined from 2022 highs, partially offset by stronger marketing margins. Advantaged Volume Growth – Higher volumes from advantaged projects, increased earnings by $480 million, mainly driven by the Beaumont expansion. Base Volume – Lower base volumes decreased earnings by $560 million driven by higher planned maintenance and divestments, partially offset by improved reliability. Structural Cost Savings – Increased earnings by $450 million. Expenses – Higher expenses decreased earnings by $830 million, mainly driven by Beaumont project activities and planned maintenance costs. Other – All other items decreased earnings by $10 million. Timing Effects – Absence of unfavorable timing effects associated with derivatives increased earnings by $330 million. Identified Items (1) – 2022 $(684) million loss was primarily as a result of impairments and unfavorable tax items. 2023 $144 million gain driven by favorable tax effects partially offset by additional European taxes on the energy sector. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 53 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy Products Operational Results (thousands of barrels daily) 2024 2023 2022 Refinery throughput United States 1,865 1,848 1,702 Canada 399 407 418 Europe 1,039 1,166 1,192 Asia Pacific 432 498 539 Other 165 149 179 Worldwide 3,900 4,068 4,030 Energy Products sales (1) United States 2,722 2,633 2,426 Non-U.S. 2,696 2,828 2,921 Worldwide 5,418 5,461 5,347 Gasoline, naphthas 2,251 2,288 2,232 Heating oils, kerosene, diesel 1,769 1,795 1,774 Aviation fuels 355 336 338 Heavy fuels 200 214 235 Other energy products 844 829 768 Worldwide 5,418 5,461 5,347 (1) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. Chemical Products ExxonMobil is a leading global manufacturer and marketer of petrochemicals that support modern living. Chemical Products help meet society’s essential needs by providing a wide range of innovative products efficiently and responsibly. The Company is uniquely positioned with a combination of industry-leading scale, integration, and proprietary technology, which are fundamental to producing affordable products that are more sustainable, use less material, save energy, and reduce waste. These competitive advantages are underpinned by operational excellence, advantaged investments, and cost discipline. This segment includes olefins, polyolefins, and intermediates. Over the long term, worldwide demand for chemicals is expected to grow faster than the economy, driven by global population growth, an expanding middle class, and improving living standards. Chemical Products integration with refineries, performance product mix, and project execution capability improves returns on investments across a range of market environments. In 2024, chemical industry margins remained bottom-of-cycle, below the pre-COVID 10-year historical range (2010-2019), as capacity additions from 2022-2024 have exceeded demand growth. The Company optimized production across our global footprint to profitably meet customer demand. Our earnings benefited from record reliability, record high-value products sales, and a large North American footprint where low ethane prices provide a feed advantage. Key Recent Events China Chemical Complex: ExxonMobil is investing in a petrochemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province, which is a significant step in growing our global manufacturing footprint and will be the first 100 percent foreign-owned petrochemical complex built in China. The facility will be focused on producing our unique high-performance polyethylene and polypropylene products. When completed, the complex will have three polyethylene and two polypropylene production lines for a combined capacity of over 2.5 million metric tons per year. This capacity will more efficiently serve China’s domestic demand, which is currently being met with imports. Advanced Recycling: ExxonMobil is combining proprietary technology and advantaged integrated sites to process hard-to-recycle plastic waste. The Company’s first Baytown facility started up in 2022 and represents one of the largest advanced recycling facilities in North America. ExxonMobil is expanding advanced recycling capacity with two additional Baytown units starting up during 2025. The Company plans to build additional units to reach a global recycling capacity of 1 billion pounds per year by 2027. 54 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Chemical Products Financial Results (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) United States 1,627 1,626 2,328 Non-U.S. 950 11 1,215 Total 2,577 1,637 3,543 Identified Items (1) United States (43) 32 — Non-U.S. (52) (420) — Total (95) (388) — Earnings (loss) excluding Identified Items (1) (Non-GAAP) United States 1,670 1,594 2,328 Non-U.S. 1,002 431 1,215 Total 2,672 2,025 3,543 (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 2024 Chemical Products Earnings Driver Analysis (millions of dollars) Margin – Improved company margins on North American ethane feed advantage and improved product realizations increased earnings by $890 million, despite continued bottom-of-cycle market conditions. Advantaged Volume Growth – Record high-value product sales increased earnings by $410 million. Base Volume – Portfolio optimization and product sales mix decreased earnings by $270 million. Structural Cost Savings – Increased earnings by $190 million. Expenses – Higher advantaged project spend and inflation effects decreased earnings by $490 million. Other – All other items decreased earnings by $80 million. Identified Items (1) – 2023 $(388) million loss was primarily driven by impairments; 2024 $(95) million loss driven by impairments. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 55 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2023 Chemical Products Earnings Driver Analysis (millions of dollars) Margin – Weaker margins decreased earnings by $870 million due to bottom-of-cycle price conditions, as industry supply additions continued to outpace demand growth. Advantaged Volume Growth – High-value product sales growth increased earnings by $210 million. Base Volume – Reduced volumes from product sales mix decreased earnings by $360 million. Structural Cost Savings – Increased earnings by $220 million. Expenses – Higher project spend and scheduled maintenance costs decreased earnings by $690 million. Other – All other items decreased earnings by $30 million. Identified Items (1) – 2023 $(388) million loss was primarily driven by impairments. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. Chemical Products Operational Results (thousands of metric tons) 2024 2023 2022 Chemical product sales (2) United States 7,038 6,779 7,270 Non-U.S. 12,354 12,603 11,897 Worldwide 19,392 19,382 19,167 (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 56 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Specialty Products ExxonMobil Specialty Products is a combination of business units that manufacture and market a range of performance products, including high-quality lubricants, basestocks, waxes, synthetics, elastomers, and resins. Leveraging ExxonMobil’s proprietary technologies, Specialty Products focuses on providing performance products that help customers improve efficiency in the transportation and industrial sectors. Specialty Products is well-positioned to help meet growth in lubricants demand through advantaged projects that leverage ExxonMobil's integration, technology, and world-class brands, such as Mobil 1 TM . In 2024, Specialty Products continued to deliver strong earnings from our portfolio of high-value products and brand market position. Key Recent Events Singapore Resid Upgrade project: Progressed project with expected start-up in 2025, which will leverage two proprietary technologies to upgrade fuel oil to Group II lubes and diesel, further strengthening ExxonMobil’s position as the largest basestock producer in the world. Proxxima TM Systems: ExxonMobil's advanced polyolefin thermoset resin uses components of gasoline and catalyst technology to create a material that is lighter, stronger, and more durable than conventional products, providing alternatives for the construction, coatings and transportation industries. These systems are designed to drive product substitutions in existing markets and enable expansion into new applications like structural composites and steel substitutes. ExxonMobil plans to grow the manufacturing capacity of Proxxima TM products up to 200,000 tons per year by 2030. Carbon Materials venture: ExxonMobil is growing its carbon materials venture by applying proprietary process technology to capture attractive opportunities in the battery anode market. The Company has developed an advanced coke product by converting low-value, bottom-of-the-barrel molecules that can deliver a higher performance differentiated graphite. These carbon materials enable batteries that can provide up to 30 percent higher capacity, 30 percent faster charging time, and extended battery life. Specialty Products Financial Results (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) United States 1,576 1,536 1,190 Non-U.S. 1,476 1,178 1,225 Total 3,052 2,714 2,415 Identified Items (1) United States (4) 12 — Non-U.S. (9) (105) (40) Total (13) (93) (40) Earnings (loss) excluding Identified Items (1) (Non-GAAP) United States 1,580 1,524 1,190 Non-U.S. 1,485 1,283 1,265 Total 3,065 2,807 2,455 (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. Due to rounding, numbers presented may not add up precisely to the totals indicated. 57 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2024 Specialty Products Earnings Driver Analysis (millions of dollars) Margin – Stronger basestocks and finished lubes margins increased earnings by $590 million. Advantaged Volume Growth – High-value products volume growth increased earnings by $70 million. Base Volume – Decreased earnings by $10 million. Structural Cost Savings – Increased earnings by $130 million. Expenses – Higher expenses including new product development costs, decreased earnings by $300 million. Other – All other items decreased earnings by $220 million, mainly unfavorable foreign exchange effects and absence of prior year favorable year-end inventory effects. Identified Items (1) – 2023 $(93) million loss mainly from impairments; 2024 $(13) million loss. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 58 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2023 Specialty Products Earnings Driver Analysis (millions of dollars) Margin – Stronger margins increased earnings by $450 million, driven by high-value products and lower feed costs. Advantaged Volume Growth – High-value products volume growth decreased earnings by $20 million. Base Volume – Base Volumes decreased earnings by $100 million on weaker global demand. Structural Cost Savings – Increased earnings by $120 million. Expenses – Higher expenses decreased earnings by $100 million. Identified Items (1) – 2022 $(40) million loss from impairments; 2023 $(93) million loss mainly from impairments. (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. Specialty Products Operational Results (thousands of metric tons) 2024 2023 2022 Specialty Products sales (2) United States 1,922 1,962 2,049 Non-U.S. 5,745 5,635 5,762 Worldwide 7,666 7,597 7,810 (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 59 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Corporate and Financing Corporate and Financing is comprised of corporate activities that support ExxonMobil's operating segments and Low Carbon Solutions business. Corporate activities include general administrative support functions, financing, and insurance activities. Low Carbon Solutions activities will be included in Corporate and Financing until the business is established with a material level of assets and revenue. Corporate and Financing Financial Results (millions of dollars) 2024 2023 2022 Earnings (loss) (U.S. GAAP) (1,372) (1,791) (1,663) Identified Items (1) 30 76 302 Earnings (loss) excluding Identified Items (1) (Non-GAAP) (1,402) (1,867) (1,965) (1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items. 2024 Corporate and Financing expenses were $1,372 million in 2024 compared to $1,791 million in 2023, with the decrease mainly due to lower financing costs. 2023 Corporate and Financing expenses were $1,791 million in 2023 compared to $1,663 million in 2022, with the increase mainly due to the absence of prior year favorable tax-related items, partly offset by lower financing costs. 60 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Cash (millions of dollars) 2024 2023 2022 Net cash provided by/(used in) Operating activities 55,022 55,369 76,797 Investing activities (19,938) (19,274) (14,742) Financing activities (42,789) (34,297) (39,114) Effect of exchange rate changes (676) 105 (78) Increase/(decrease) in cash and cash equivalents (8,381) 1,903 22,863 Total cash and cash equivalents (December 31) 23,187 31,568 29,665 Total cash and cash equivalents were $23.2 billion at the end of 2024, down $8.4 billion from the prior year. The major sources of funds in 2024 were net income including noncontrolling interests of $35.1 billion, the adjustment for the noncash provision of $23.4 billion for depreciation and depletion, proceeds from asset sales of $5.0 billion, other investing activities of $1.9 billion, and cash acquired from mergers and acquisitions of $0.8 billion. The major uses of funds included spending for additions to property, plant and equipment of $24.3 billion; dividends to shareholders of $16.7 billion; the purchase of ExxonMobil stock of $19.6 billion; debt repayment of $5.9 billion; additional investments and advances of $3.3 billion; and an increase in working capital of $1.8 billion. Total cash and cash equivalents were $31.6 billion at the end of 2023, up $1.9 billion from the prior year. The major sources of funds in 2023 were net income including noncontrolling interests of $37.4 billion, the adjustment for the noncash provision of $20.6 billion for depreciation and depletion, proceeds from asset sales of $4.1 billion, and other investing activities of $1.6 billion. The major uses of funds included spending for additions to property, plant and equipment of $21.9 billion; dividends to shareholders of $14.9 billion; the purchase of ExxonMobil stock of $17.7 billion; additional investments and advances of $3.0 billion; and a change in working capital of $4.3 billion. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. On December 31, 2024, the Corporation had undrawn short-term committed lines of credit of $0.2 billion and undrawn long-term lines of credit of $1.3 billion. To support cash flows in future periods, the Corporation will need to continually find or acquire and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields to eventually produce at declining rates for the remainder of their economic life. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. In particular, the Corporation’s key tight-oil plays have higher initial decline rates which tend to moderate over time. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms. The Corporation has long been successful at mitigating the effects of natural field decline through disciplined investments in quality opportunities and project execution. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of investments that may vary depending on the oil and gas price environment; and international trade patterns and relations. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A for a more complete discussion of risks. The Corporation’s financial strength enables it to make large, long-term capital expenditures. Cash Capex in 2024 was $25.6 billion, reflecting the Corporation’s continued active investment program, and includes plans to invest in the range of $27 billion to $29 billion in 2025 (see the Cash Capital Expenditures section for more details). Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. 61 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Corporation, as part of its ongoing asset management program, continues to evaluate its mix of assets for potential upgrade. Because of the ongoing nature of this program, dispositions will continue to be made from time to time which will result in either gains or losses. Additionally, the Corporation continues to evaluate opportunities to enhance its business portfolio through acquisitions of assets or companies, and enters into such transactions from time to time. Key criteria for evaluating acquisitions include strategic fit, cost and other synergies, potential for future growth, low cost of supply, and attractive valuations. Acquisitions may be made with cash, shares of the Corporation’s common stock, or both. Cash Flow from Operating Activities 2024 Cash provided by operating activities totaled $55.0 billion in 2024, $0.3 billion lower than 2023. The major source of funds was net income including noncontrolling interests of $35.1 billion, a decrease of $2.3 billion. The noncash provision for depreciation and depletion was $23.4 billion, up $2.8 billion from the prior year. The adjustment for the net gain on asset sales was $1.2 billion, an increase of $0.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $0.2 billion, compared to an increase of $0.5 billion in 2023. Changes in operational working capital, excluding cash and debt, decreased cash in 2024 by $1.8 billion. 2023 Cash provided by operating activities totaled $55.4 billion in 2023, $21.4 billion lower than 2022. The major source of funds was net income including noncontrolling interests of $37.4 billion, a decrease of $20.2 billion. The noncash provision for depreciation and depletion was $20.6 billion, down $3.4 billion from the prior year. The adjustment for the net gain on asset sales was $0.5 billion, a decrease of $0.5 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $0.5 billion, compared to a reduction of $2.4 billion in 2022. Changes in operational working capital, excluding cash and debt, decreased cash in 2023 by $4.3 billion. Cash Flow from Investing Activities 2024 Cash used in investing activities netted to $19.9 billion in 2024, $0.7 billion higher than 2023. Spending for property, plant and equipment of $24.3 billion increased $2.4 billion from 2023. Proceeds from asset sales and returns of investments of $5.0 billion compared to $4.1 billion in 2023. Additional investments and advances were $0.3 billion higher in 2024, while proceeds from other investing activities including collection of advances increased by $0.4 billion. 2023 Cash used in investing activities netted to $19.3 billion in 2023, $4.5 billion higher than 2022. Spending for property, plant and equipment of $21.9 billion increased $3.5 billion from 2022. Proceeds from asset sales and returns of investments of $4.1 billion compared to $5.2 billion in 2022. Additional investments and advances were $0.1 billion lower in 2023, while proceeds from other investing activities including collection of advances increased by $0.1 billion. 62 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Cash Flow from Financing Activities 2024 Cash used in financing activities was $42.8 billion in 2024, $8.5 billion higher than 2023. Dividend payments on common shares increased to $3.84 per share from $3.68 per share and totaled $16.7 billion. During 2024, the Corporation utilized cash to repay debt of $5.9 billion. During 2024, the Corporation continued its share repurchase program, including the purchase of 167 million shares at a book value of $19.1 billion in 2024. In its 2024 Corporate Plan Update released December 11, 2024, the Corporation stated that it is expected to continue its share repurchase program with a $20 billion repurchase pace per year through 2026, assuming reasonable market conditions. The stock repurchase program does not obligate the Company to acquire any particular amount of common stock, and it may be discontinued or resumed at any time. The timing and amount of shares actually purchased in the future will depend on market, business, and other factors. 2023 Cash used in financing activities was $34.3 billion in 2023, $4.8 billion lower than 2022. Dividend payments on common shares increased to $3.68 per share from $3.55 per share and totaled $14.9 billion. During 2023, the Corporation continued its share repurchase program for up to $50 billion in shares through 2024, including the purchase of 162 million shares at a book value of $17.5 billion in 2023. Contractual Obligations The Corporation has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs. These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, take-or-pay and unconditional purchase obligations, and firm capital commitments. See Notes 9 , 11 , 14 and 17 for information related to asset retirement obligations, leases, long-term debt and pensions, respectively. In addition, the Corporation also enters into commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. These commitments are not meaningful in assessing liquidity and cash flow, because the purchases will be offset in the same periods by cash received from the related sales transactions. Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. These obligations mainly pertain to pipeline, manufacturing supply and terminal agreements. The total obligation at year-end 2024 for take-or-pay and unconditional purchase obligations was $49.9 billion. Cash payments expected in 2025 and 2026 are $5.5 billion and $6.3 billion, respectively. Guarantees The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2024 for guarantees relating to notes, loans and performance under contracts ( Note 16 ). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. Where it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence. Guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 63 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Financial Strength On December 31, 2024, the Corporation had total unused short-term committed lines of credit of $0.2 billion ( Note 6 ) and total unused long-term committed lines of credit of $1.3 billion ( Note 14 ). The table below shows the Corporation’s consolidated debt to capital ratios. (percent) 2024 2023 2022 Debt to capital 13.4 16.4 16.9 Net debt to capital (1) 6.5 4.5 5.4 (1) Net debt is total debt less cash and cash equivalents excluding restricted cash. Net debt to capital ratio is net debt divided by net debt plus total equity. Total debt is the sum of notes and loans payable and long-term debt, as reported in the Consolidated Balance Sheet. Management views the Corporation’s financial strength to be a competitive advantage of strategic importance. The Corporation’s financial position gives it the opportunity to access the world’s capital markets across a range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. The Corporation's total debt level remained relatively flat in 2024, ending the year at $41.7 billion. Litigation and Other Contingencies As discussed in Note 16 , a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 16 for additional information on legal proceedings and other contingencies. CAPITAL AND EXPLORATION EXPENDITURES Capital and exploration expenditures (Capex) represents the combined total of additions at cost to property, plant and equipment, and exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value of ExxonMobil shares used to acquire assets, and depreciation on the cost of exploration support equipment and facilities recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures. (millions of dollars) 2024 2023 U.S. Non-U.S. Total U.S. Non-U.S. Total Upstream (including exploration expenses) 11,252 10,596 21,848 8,813 10,948 19,761 Energy Products 756 1,610 2,366 1,195 1,580 2,775 Chemical Products 739 1,332 2,071 751 1,962 2,713 Specialty Products 145 270 415 63 391 454 Other 851 — 851 622 — 622 Total Capex 13,743 13,808 27,551 11,444 14,881 26,325 Capex in 2024 was $27.6 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. Upstream spending of $21.8 billion in 2024 was up $2.1 billion from 2023, reflecting higher spend in the U.S. Permian Basin following the Pioneer acquisition. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The percentage of proved developed reserves was 63 percent of total proved reserves at year-end 2024, and has been over 60 percent for the last ten years. Capital investments in the three Product Solutions businesses totaled $4.9 billion in 2024, a decrease of $1.1 billion from 2023, reflecting lower global project spending. Key investments in 2024 included the China petrochemical complex and Singapore Resid Upgrade project. Other spend of $0.9 billion primarily reflects investments in the Low Carbon Solutions business to advance carbon capture and storage, lithium, and virtually carbon-free hydrogen (with approximately 98% of the carbon captured and stored) projects and technologies. 64 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CASH CAPITAL EXPENDITURES (Non-GAAP) The Corporation has transitioned to providing forward investment guidance on a cash capital expenditures (Cash Capex) basis instead of the historical capital and exploration expense (Capex) basis. This approach is a useful measure for investors to understand the cash impact of investments in the business and is more aligned with standard industry practice. Cash Capex is the sum of Additions to property, plant and equipment; Additional investments and advances; and Other investing activities including collection of advances; reduced by Inflows from noncontrolling interests for major projects, each from the Consolidated Statement of Cash Flows. The components of Cash Capex and a reconciliation to the previous Capex metric are presented in the following table: (millions of dollars) 2024 2023 Capital and Exploration Expenditures (Capex) 27,551 26,325 ExxonMobil’s share of Capex for equity companies (2,546) (2,741) Exploration expenses excluding prior year dry holes (755) (567) Other activities including finance leases 56 (1,098) Additions to property, plant and equipment 24,306 21,919 Additional investments and advances 3,299 2,995 Other investing activities including collection of advances (1,926) (1,562) Inflows from noncontrolling interests for major projects (32) (124) Total Cash Capex (Non-GAAP) 25,647 23,228 (millions of dollars) 2024 2023 U.S. Non-U.S. Total U.S. Non-U.S. Total Upstream 11,276 8,985 20,261 8,783 8,122 16,905 Energy Products 705 1,513 2,218 1,284 1,547 2,831 Chemical Products 671 1,212 1,883 718 1,702 2,420 Specialty Products 145 263 408 63 391 454 Other 877 — 877 618 — 618 Total Cash Capex (Non-GAAP) 13,674 11,973 25,647 11,466 11,762 23,228 Cash Capex in 2024 was $25.6 billion. The Corporation plans to invest in the range of $27 billion to $29 billion in 2025. Included in the 2025 capital spend range is $8.1 billion of firm capital commitments. An additional $10.0 billion of firm capital commitments have been made for years 2026 and beyond. Actual spending could vary depending on the progress of individual projects and property acquisitions. 65 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS TAXES (millions of dollars) 2024 2023 2022 Income taxes 13,810 15,429 20,176 Effective income tax rate 33% 33% 33% Total other taxes and duties 29,894 32,191 31,455 Total 43,704 47,620 51,631 2024 Total taxes on the Corporation’s income statement were $43.7 billion in 2024, a decrease of $3.9 billion from 2023. Income tax expense, both current and deferred, was $13.8 billion compared to $15.4 billion in 2023. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This was flat compared to 2023. Total other taxes and duties of $29.9 billion in 2024 decreased $2.3 billion from 2023. 2023 Total taxes on the Corporation’s income statement were $47.6 billion in 2023, a decrease of $4.0 billion from 2022. Income tax expense, both current and deferred, was $15.4 billion compared to $20.2 billion in 2022. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This was flat compared to 2022, with higher effective rates from various jurisdictions offset by a lower impact from additional European taxes on the energy sector. Total other taxes and duties of $32.2 billion in 2023 increased $0.7 billion from 2022. ENVIRONMENTAL MATTERS Environmental Expenditures (millions of dollars) 2024 2023 Capital expenditures 3,607 2,799 Other expenditures 5,348 4,336 Total 8,955 7,135 Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water, and ground. These include significant investments in refining infrastructure and technology to manufacture clean fuels; projects to monitor and reduce air, water, and waste emissions, both from the Company’s operations and from other companies; and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2024 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $9.0 billion, of which $5.3 billion were included in expenses with the remainder in capital expenditures. As the Corporation progresses its emission-reduction plans, worldwide environmental expenditures are expected to increase to approximately $12 billion annually in 2025 and 2026, with capital expenditures expected to account for approximately 55 percent of the total in each year. Environmental Liabilities The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2024 for environmental liabilities were $277 million ($208 million in 2023), and the balance sheet reflects liabilities of $734 million as of December 31, 2024, and $701 million as of December 31, 2023. 66 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS MARKET RISKS Marker (1) 2024 2023 2022 Brent ($ per barrel) 80.76 82.62 101.19 Henry Hub ($ per metric million British thermal unit) 2.27 2.74 6.65 TTF ($ per metric million British thermal unit) 10.77 15.15 40.22 (1) Markers reflect the average prices from the year. Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings have varied across the Corporation's operating segments. For the year 2025, a $1 per barrel change in the Brent price would have an approximately $650 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. This Brent sensitivity includes oil-linked LNG sales which make up approximately 10 percent of the sensitivity. A $0.10 per million metric British thermal unit change in the Henry Hub price would have an approximately $75 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per million metric British thermal unit change in the Title Transfer Facility (TTF) price would have an approximately $20 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. This TTF sensitivity primarily represents LNG sales. These price markers have a direct impact on our realized prices. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period. In the very competitive petroleum and petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage. In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information on intersegment revenue. Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC or OPEC+ and other major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. The Corporation evaluates investments over a range of prices, including estimated greenhouse gas emission costs even in jurisdictions without a current greenhouse gas pricing policy. The Corporation has an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure assets are contributing to the Corporation’s strategic objectives. Risk Management The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2024 and 2023, or results of operations for the years ended 2024, 2023, and 2022. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position, results of operations or liquidity exist as a result of the derivatives described in Note 13 . The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. 67 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects. The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing, and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material. CRITICAL ACCOUNTING ESTIMATES The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission and other new business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, Proxxima TM systems, carbon materials, and lithium. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1 . Oil and Natural Gas Reserves The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of reservoir and well performance, development and production costs, and other factors. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2 . Oil and natural gas reserves include both proved and unproved reserves. • Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year. Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time. The Corporation is reasonably certain that proved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels. • Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered. Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity. 68 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Unit-of-Production Depreciation Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Acquisition costs of proved properties are depreciated using a ratio of asset cost to total proved reserves while capitalized drilling and developments costs are depreciated using a ratio of actual production volumes to proved developed reserves. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. Fair Value Used in Business Combinations In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on their respective estimated fair values as of the date of acquisition. If applicable, any excess of the purchase price over the fair value is recorded as goodwill. The assessment of fair value is based upon the views of a likely market participant group. On May 3, 2024, the Corporation acquired Pioneer Natural Resources Company (Pioneer), an independent oil and gas exploration and production company. To effect the acquisition, we issued 545 million shares of ExxonMobil common stock having a fair value of $63 billion on the acquisition date, and assumed debt with a fair value of $5 billion. In respect of the Pioneer acquisition, the most significant amount of judgment involved the estimated fair values of property, plant and equipment related to crude oil and natural gas properties, for which we used discounted cash flow models. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices consistent with the average of third-party industry experts, drilling and development costs, and risk-adjusted discount rates. The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition. Actual results may differ from the projected results used to determine fair value. See N ote 21 for further information regarding the Pioneer acquisition during 2024. Impairment The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360, can be indicators of potential impairment as well. In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of 69 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins. Global Outlook and Cash Flow Assessment. The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Global Outlook (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from unconventional operated assets in the Permian Basin, and in Pioneer assets by 2035. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. While third-party scenarios may be used for these purposes, they are not used as a basis for developing future cash flows for impairment assessments. As part of the Corporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy. Fair Value of Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. Other Impairment Estimates. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale and to determine the fair value less cost to sell. Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment. Recent Impairments. Impairments in 2024 were immaterial. In 2023, the Corporation recognized after-tax charges of $3.4 billion, primarily related to the idled Upstream Santa Ynez Unit assets and associated facilities in California, which reflected the continuing challenges in the state regulatory environment that impeded progress towards restoring operations. Other impairments in the year included a $0.6 billion charge related to an Upstream equity investment. 70 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In early 2022, in response to Russia’s military action in Ukraine, the Corporation announced that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first quarter 2022 results included after-tax charges of $3.0 billion representing the impairment of its Upstream operations related to Sakhalin. (Refer to Note 2 for further information on Russia.) During 2022, other after-tax impairment charges of $1.6 billion and $0.3 billion were recognized in Upstream and Energy Products, respectively. Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets. For further information regarding impairments in equity method investments, property, plant, and equipment, and suspended wells, refer to Notes 7 , 9 , and 10 , respectively. Asset Retirement Obligations The Corporation is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. See Note 9 for further information regarding asset retirement obligations. Pension Benefits The Corporation and its affiliates sponsor about 70 defined benefit (pension) plans in 40 countries. Note 17 provides details on pension obligations, fund assets, and pension expense. Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets. For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes. The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate. Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2024 was 6.8 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 4 percent and 5 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted-average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax. Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees. 71 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Litigation and Tax Contingencies A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. For contingencies where an unfavorable outcome is reasonably possible and significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. As described in Note 16 , for purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16 . Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement. The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19 . 72 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management, including the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2024. The Corporation excluded Pioneer from our assessment of internal control over financial reporting as of December 31, 2024, because it was acquired by the Corporation in a business combination during 2024. Total assets and total revenues of Pioneer, a wholly owned subsidiary, represent nineteen percent and four percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2024, as stated in their report included in the Financial Section of this report. Darren W. Woods Chief Executive Officer Kathryn A. Mikells Senior Vice President and Chief Financial Officer Len M. Fox Vice President, Controller and Tax (Principal Accounting Officer) 73 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Exxon Mobil Corporation Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheet of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as of December 31, 2024 and 2023, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2024, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Corporation's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Corporation as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Corporation's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Pioneer Natural Resources Company ("Pioneer") from its assessment of internal control over financial reporting as of December 31, 2024 because it was acquired by the Corporation in a business combination during 2024. We have also excluded Pioneer from our audit of internal control over financial reporting. Pioneer is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent nineteen percent and four percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 74 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. The Impact of Proved Developed Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net As described in Notes 1, 9 and 18 to the consolidated financial statements, the Corporation's consolidated upstream property, plant and equipment (PP&E), net balance was $226.0 billion as of December 31, 2024, and the related depreciation and depletion expense for the year ended December 31, 2024 was $19.5 billion. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Acquisition costs of proved properties are depreciated using a ratio of asset cost to total proved reserves while capitalized drilling and development costs are depreciated using a ratio of actual production volumes to proved developed reserves. The estimation of proved oil and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of reservoir and well performance, development and production costs, and other factors. As further disclosed by management, reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group (together "management's specialists"). The principal considerations for our determination that performing procedures relating to the impact of proved developed oil and natural gas reserves on upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management's specialists, when developing the estimates of proved developed oil and natural gas reserves and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil and natural gas reserves. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved developed oil and natural gas reserves. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil and natural gas reserves. As a basis for using this work, the specialists' qualifications were understood and the Corporation’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes; and (iii) evaluating the specialists' findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. Merger with Pioneer - Valuation of Crude Oil and Natural Gas Properties As described in Note 21 to the consolidated financial statements, the Corporation acquired Pioneer in a transaction accounted for as a business combination, requiring that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date, which included approximately $84 billion related to the fair values of acquired PP&E of which a significant portion relates to crude oil and natural gas properties. Crude oil and natural gas properties were valued using discounted cash flow models. Inputs and assumptions used in the discounted cash flow models included estimates for commodity prices, future production volumes, drilling and development costs, and risk-adjusted discount rates. The principal considerations for our determination that performing procedures relating to the valuation of crude oil and natural gas properties acquired in the Pioneer merger is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value estimate of crude oil and natural gas properties acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to commodity prices, future production volumes, drilling and development costs, and risk-adjusted discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of acquired crude oil and natural gas properties. These procedures also included, among others (i) reading the merger agreement; (ii) testing management’s process for developing the fair value estimate of crude oil and natural gas properties acquired; (iii) evaluating the appropriateness of the discounted cash flow models; (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow models related to historical production volumes and third-party commodity prices; and (v) evaluating the reasonableness of significant assumptions used by management related to commodity prices, future production volumes, drilling and development costs, and risk-adjusted discount rates. Evaluating the 75 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM commodity prices assumptions involved comparing the prices to observable market data. Evaluating management’s assumptions relating to future production volumes and drilling and development costs involved evaluating whether the assumptions used by management were reasonable as compared to historical results of Pioneer. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow models and the reasonableness of the risk-adjusted discount rates assumptions. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the Corporation’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. /s/ PricewaterhouseCoopers LLP Houston, Texas February 19, 2025 We have served as the Corporation’s auditor since 1934. 76 CONSOLIDATED STATEMENT OF INCOME (millions of dollars) Note Reference Number 2024 2023 2022 Revenues and other income Sales and other operating revenue 18 339,247 334,697 398,675 Income from equity affiliates 7 6,194 6,385 11,463 Other income 4,144 3,500 3,542 Total revenues and other income 349,585 344,582 413,680 Costs and other deductions Crude oil and product purchases 199,454 193,029 228,959 Production and manufacturing expenses 39,609 36,885 42,609 Selling, general and administrative expenses 9,976 9,919 10,095 Depreciation and depletion (includes impairments) 2 , 9 23,442 20,641 24,040 Exploration expenses, including dry holes 826 751 1,025 Non-service pension and postretirement benefit expense 17 121 714 482 Interest expense 996 849 798 Other taxes and duties 19 26,288 29,011 27,919 Total costs and other deductions 300,712 291,799 335,927 Income (loss) before income taxes 48,873 52,783 77,753 Income tax expense (benefit) 19 13,810 15,429 20,176 Net income (loss) including noncontrolling interests 35,063 37,354 57,577 Net income (loss) attributable to noncontrolling interests 1,383 1,344 1,837 Net income (loss) attributable to ExxonMobil 33,680 36,010 55,740 Earnings (loss) per common share (dollars) 12 7.84 8.89 13.26 Earnings (loss) per common share - assuming dilution (dollars) 12 7.84 8.89 13.26 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 77 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (millions of dollars) 2024 2023 2022 Net income (loss) including noncontrolling interests 35,063 37,354 57,577 Other comprehensive income (loss) (net of income taxes) Foreign exchange translation adjustment ( 3,550 ) 1,241 ( 3,482 ) Adjustment for foreign exchange translation (gain)/loss included in net income — 609 — Postretirement benefits reserves adjustment (excluding amortization) 557 ( 369 ) 3,395 Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs 43 61 403 Total other comprehensive income (loss) ( 2,950 ) 1,542 316 Comprehensive income (loss) including noncontrolling interests 32,113 38,896 57,893 Comprehensive income (loss) attributable to noncontrolling interests 1,063 1,605 1,659 Comprehensive income (loss) attributable to ExxonMobil 31,050 37,291 56,234 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 78 CONSOLIDATED BALANCE SHEET (millions of dollars) Note Reference Number December 31, 2024 December 31, 2023 ASSETS Current assets Cash and cash equivalents 23,029 31,539 Cash and cash equivalents – restricted 158 29 Notes and accounts receivable – net 6 43,681 38,015 Inventories Crude oil, products and merchandise 3 19,444 20,528 Materials and supplies 4,080 4,592 Other current assets 1,598 1,906 Total current assets 91,990 96,609 Investments, advances and long-term receivables 8 47,200 47,630 Property, plant and equipment, at cost, less accumulated depreciation and depletion 9 294,318 214,940 Other assets, including intangibles – net 19,967 17,138 Total Assets 453,475 376,317 LIABILITIES Current liabilities Notes and loans payable 6 4,955 4,090 Accounts payable and accrued liabilities 6 61,297 58,037 Income taxes payable 4,055 3,189 Total current liabilities 70,307 65,316 Long-term debt 14 36,755 37,483 Postretirement benefits reserves 17 9,700 10,496 Deferred income tax liabilities 19 39,042 24,452 Long-term obligations to equity companies 1,346 1,804 Other long-term obligations 25,719 24,228 Total Liabilities 182,869 163,779 Commitments and contingencies 16 EQUITY Common stock without par value ( 9,000 million shares authorized, 8,019 million shares issued) 46,238 17,781 Earnings reinvested 470,903 453,927 Accumulated other comprehensive income 4 ( 14,619 ) ( 11,989 ) Common stock held in treasury ( 3,666 million shares in 2024 and 4,048 million shares in 2023) ( 238,817 ) ( 254,917 ) ExxonMobil share of equity 263,705 204,802 Noncontrolling interests 6,901 7,736 Total Equity 270,606 212,538 Total Liabilities and Equity 453,475 376,317 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 79 CONSOLIDATED STATEMENT OF CASH FLOWS (millions of dollars) Note Reference Number 2024 2023 2022 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) including noncontrolling interests 35,063 37,354 57,577 Adjustments for noncash transactions Depreciation and depletion (includes impairments) 2 , 9 23,442 20,641 24,040 Deferred income tax charges/(credits) 19 ( 865 ) 634 3,758 Postretirement benefits expense in excess of/(less than) net payments ( 358 ) 90 ( 2,981 ) Other long-term obligation provisions in excess of/(less than) payments ( 1,712 ) ( 1,501 ) ( 1,932 ) Dividends received greater than/(less than) equity in current earnings of equity companies 191 509 ( 2,446 ) Changes in operational working capital, excluding cash and debt Notes and accounts receivable reduction/(increase) ( 6,030 ) 4,370 ( 11,019 ) Inventories reduction/(increase) ( 1,812 ) ( 3,472 ) ( 6,947 ) Other current assets reduction/(increase) 389 ( 426 ) ( 688 ) Accounts and other payables increase/(reduction) 5,627 ( 4,727 ) 18,460 Net (gain)/loss on asset sales 5 ( 1,223 ) ( 513 ) ( 1,034 ) All other items - net 2,310 2,410 9 Net cash provided by operating activities 55,022 55,369 76,797 CASH FLOWS FROM INVESTING ACTIVITIES Additions to property, plant and equipment ( 24,306 ) ( 21,919 ) ( 18,407 ) Proceeds from asset sales and returns of investments 4,987 4,078 5,247 Additional investments and advances ( 3,299 ) ( 2,995 ) ( 3,090 ) Other investing activities including collection of advances 1,926 1,562 1,508 Cash acquired from mergers and acquisitions 754 — — Net cash used in investing activities ( 19,938 ) ( 19,274 ) ( 14,742 ) CASH FLOWS FROM FINANCING ACTIVITIES Additions to long-term debt (1) 899 939 637 Reductions in long-term debt ( 1,150 ) ( 15 ) ( 5 ) Additions to short-term debt — — 198 Reductions in short-term debt ( 4,743 ) ( 879 ) ( 8,075 ) Additions/(reductions) in debt with three months or less maturity ( 18 ) ( 284 ) 25 Contingent consideration payments ( 27 ) ( 68 ) ( 58 ) Cash dividends to ExxonMobil shareholders ( 16,704 ) ( 14,941 ) ( 14,939 ) Cash dividends to noncontrolling interests ( 658 ) ( 531 ) ( 267 ) Changes in noncontrolling interests ( 791 ) ( 894 ) ( 1,493 ) Inflows from noncontrolling interests for major projects 32 124 18 Common stock acquired ( 19,629 ) ( 17,748 ) ( 15,155 ) Net cash provided by (used in) financing activities ( 42,789 ) ( 34,297 ) ( 39,114 ) Effects of exchange rate changes on cash ( 676 ) 105 ( 78 ) Increase/(decrease) in cash and cash equivalents ( 8,381 ) 1,903 22,863 Cash and cash equivalents at beginning of year 31,568 29,665 6,802 Cash and cash equivalents at end of year 23,187 31,568 29,665 (1) Includes $ 568 million issued to facilitate the sale of an entity where the buyer assumed the debt upon closing; no longer on the Consolidated Balance Sheet at the end of 2023. Non-Cash Transaction: The Corporation acquired Pioneer in an all-stock transaction on May 3, 2024, having issued 545 million shares of ExxonMobil common stock having a fair value of $ 63 billion on the acquisition date and assumed debt with a fair value of $ 5 billion. See Note 21 for additional information. The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 80 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ExxonMobil Share of Equity (millions of dollars) Common Stock Earnings Reinvested Accumulated Other Comprehensive Income Common Stock Held in Treasury ExxonMobil Share of Equity Non-controlling Interests Total Equity Balance as of December 31, 2021 15,746 392,059 ( 13,764 ) ( 225,464 ) 168,577 7,106 175,683 Amortization of stock-based awards 481 — — — 481 — 481 Other ( 475 ) — — — ( 475 ) 405 ( 70 ) Net income (loss) for the year — 55,740 — — 55,740 1,837 57,577 Dividends - common shares — ( 14,939 ) — — ( 14,939 ) ( 267 ) ( 15,206 ) Other comprehensive income — — 494 — 494 ( 178 ) 316 Share repurchases, at cost — — — ( 15,295 ) ( 15,295 ) ( 1,479 ) ( 16,774 ) Dispositions — — — 466 466 — 466 Balance as of December 31, 2022 15,752 432,860 ( 13,270 ) ( 240,293 ) 195,049 7,424 202,473 Amortization of stock-based awards 565 — — — 565 — 565 Other ( 514 ) ( 2 ) — — ( 516 ) 89 ( 427 ) Net income (loss) for the year — 36,010 — — 36,010 1,344 37,354 Dividends - common shares — ( 14,941 ) — — ( 14,941 ) ( 531 ) ( 15,472 ) Other comprehensive income — — 1,281 — 1,281 261 1,542 Share repurchases, at cost — — — ( 17,993 ) ( 17,993 ) ( 851 ) ( 18,844 ) Issued for acquisitions 1,978 — — 2,866 4,844 — 4,844 Dispositions — — — 503 503 — 503 Balance as of December 31, 2023 17,781 453,927 ( 11,989 ) ( 254,917 ) 204,802 7,736 212,538 Amortization of stock-based awards 735 — — — 735 — 735 Other ( 1,027 ) — — — ( 1,027 ) ( 624 ) ( 1,651 ) Net income (loss) for the year — 33,680 — — 33,680 1,383 35,063 Dividends - common shares — ( 16,704 ) — — ( 16,704 ) ( 658 ) ( 17,362 ) Other comprehensive income — — ( 2,630 ) — ( 2,630 ) ( 320 ) ( 2,950 ) Share repurchases, at cost — — — ( 19,451 ) ( 19,451 ) ( 616 ) ( 20,067 ) Issued for acquisitions 28,749 — — 34,603 63,352 — 63,352 Dispositions — — — 948 948 — 948 Balance as of December 31, 2024 46,238 470,903 ( 14,619 ) ( 238,817 ) 263,705 6,901 270,606 Common Stock Share Activity (millions of shares) Issued Held in Treasury Outstanding Balance as of December 31, 2021 8,019 ( 3,780 ) 4,239 Share repurchases, at cost — ( 165 ) ( 165 ) Dispositions — 8 8 Balance as of December 31, 2022 8,019 ( 3,937 ) 4,082 Share repurchases, at cost — ( 165 ) ( 165 ) Issued for acquisitions — 46 46 Dispositions — 8 8 Balance as of December 31, 2023 8,019 ( 4,048 ) 3,971 Share repurchases, at cost — ( 170 ) ( 170 ) Issued for acquisitions — 545 545 Dispositions — 7 7 Balance as of December 31, 2024 8,019 ( 3,666 ) 4,353 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products; and pursuit of lower-emission and other new business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, Proxxima TM systems, carbon materials, and lithium. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Note 1. Summary of Accounting Policies Principles of Consolidation and Accounting for Investments The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls and any variable interest entities where it is deemed the primary beneficiary. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues, and expenses. Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables”. Under the equity method of accounting, the Corporation recognizes its share of the net income of these companies in “Income from equity affiliates”. Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and, therefore, should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted, by law or by contract, substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans. Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value. The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in “Accumulated other comprehensive income”. Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value with changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in a similar investment of the same issuer. Revenue Recognition The Corporation generally sells crude oil, natural gas, and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold. “Sales and other operating revenue” and “Notes and accounts receivable” include revenue and receivables both within the scope of ASC 606 "Revenue from Contracts with Customers” and those outside the scope of ASC 606. Long-term receivables are primarily from receivables outside the scope of ASC 606. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant. 82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Income and Other Taxes The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”). The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is incurred. Derivative Instruments The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, foreign currency exchange rates, and interest rates that arise from existing assets, liabilities, firm commitments, and forecasted transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively. Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are immediately recognized in earnings. The Corporation may designate derivatives as fair value or cash flow hedges. For fair value hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings. For cash flow hedges, the gain or loss from the derivative instrument is initially reported as a component of other comprehensive income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings. Fair Value Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy levels 1, 2, and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy level 2 inputs are inputs other than quoted prices included within level 1 that are directly or indirectly observable for the asset or liability. Hierarchy level 3 inputs are inputs that are not observable in the market. Inventories Crude oil, products, and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less. Property, Plant, and Equipment Cost Basis. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized. Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant, and equipment and are depreciated over the service life of the related assets. 83 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life, taking obsolescence into consideration. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Service station buildings and fixed improvements are generally depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following: • a significant decrease in the market price of a long-lived asset; • a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected reserve volumes; • a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator; • an accumulation of project costs significantly in excess of the amount originally expected; • a current-period operating loss combined with a history and forecast of operating or cash flow losses; and • a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle. Asset valuation analysis, profitability reviews, and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances can be indicators of potential impairment as well. 84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins. In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices in the year. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves, and therefore, does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment. Global Outlook and Cash Flow Assessment. The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Global Outlook (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices, including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from unconventional operated assets in the Permian Basin, and in Pioneer assets by 2035. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the effects of derivative instruments. As part of the Corporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy. Fair Value of Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset group's carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. 85 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Impairments Related to Property, Plant and Equipment. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the Corporation. Environmental Liabilities Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are not discounted. Foreign Currency Translation The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Operations in the Product Solutions businesses use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and in Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as in Canada and Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Note 2. Russia In response to Russia’s military action in Ukraine, the Corporation announced in early 2022 that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. In light of this, an impairment assessment was conducted, and management determined that the carrying value of the asset group was not recoverable. As a result, the Corporation’s first-quarter 2022 earnings included after-tax charges of $ 3.4 billion largely representing the full impairment of its operations related to Sakhalin. On a before-tax basis, the charges amounted to $ 4.6 billion, substantially all of which is reflected in the line captioned “Depreciation and depletion (including impairments)” on the Consolidated Statement of Income. Effective October 14, 2022, the Russian government unilaterally terminated the Corporation’s interests in Sakhalin, transferring operations to a Russian operator. The Corporation’s fourth-quarter 2022 results include an after-tax benefit of $ 1.1 billion largely reflecting the impact of the expropriation on the Company’s various obligations related to Sakhalin. The Corporation's exit from the project resulted in approximately 150 million oil-equivalent barrels no longer qualifying as proved reserves at year-end 2022. 86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 3. Miscellaneous Financial Information Research and development expenses totaled $ 987 million in 2024, $ 879 million in 2023, and $ 824 million in 2022. Net income included before-tax aggregate foreign exchange transaction losses of $ 507 million, $ 51 million, and $ 218 million in 2024, 2023, and 2022, respectively. LIFO Inventory. In 2024, 2023, and 2022, net income included gains of $ 176 million, $ 366 million, and $ 367 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by approximately $ 10 billion and $ 14 billion at December 31, 2024 and 2023, respectively. Crude oil, products, and merchandise as of year-end 2024 and 2023 consist of the following: (millions of dollars) December 31, 2024 December 31, 2023 Crude oil 6,483 6,944 Petroleum products 6,017 6,248 Chemical products (1) 4,142 3,930 Gas/other 2,802 3,406 Total 19,444 20,528 (1) Chemical products includes basic chemicals (olefins and aromatics), polymers (such as polyolefins, adhesions, specialty elastomers, & butyl), intermediates (e.g. hydrocarbon fluids, plasticizers) and synthetics. Government Assistance. ASC 832 "Government Assistance" requires disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. During 2022 to 2024, certain governments outside the United States provided payments which, individually and in aggregate, were immaterial to the Corporation's financial results. Among these are programs where governments endeavor to stabilize or cap fuel and energy costs for local consumers. To compensate producers who sell at the government-mandated prices, these governments provide reimbursements to the producers. In 2024 and 2023, such reimbursements were negligible as were any corresponding receivables associated with these programs. In 2022, these reimbursements totaled approximately $ 1.5 billion before tax, which were reflected as reductions to the line captioned " Crude oil and product purchases " on the Consolidated Statement of Income. The terms and conditions of these programs, including their duration, vary by country. In the event that any of these programs are discontinued, the Corporation does not expect a significant impact to its financial results. Additionally, in connection with cap and trade programs in certain countries outside the United States, companies receive allowances from governments covering a specified level of emissions from facilities they operate. The terms of these programs vary by country. The Corporation records these allowances at a nominal amount, generally in "Inventories - Crude oil, products and merchandise" on the Consolidated Balance Sheet. 87 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 4. Other Comprehensive Income Information ExxonMobil Share of Accumulated Other Comprehensive Income (millions of dollars) Cumulative Foreign Exchange Translation Adjustment Postretirement Benefits Reserves Adjustment Total Balance as of December 31, 2021 ( 11,499 ) ( 2,265 ) ( 13,764 ) Current period change excluding amounts reclassified from accumulated other comprehensive income ( 3,092 ) 3,205 113 Amounts reclassified from accumulated other comprehensive income — 381 381 Total change in accumulated other comprehensive income ( 3,092 ) 3,586 494 Balance as of December 31, 2022 ( 14,591 ) 1,321 ( 13,270 ) Current period change excluding amounts reclassified from accumulated other comprehensive income (1) 1,108 ( 305 ) 803 Amounts reclassified from accumulated other comprehensive income 427 51 478 Total change in accumulated other comprehensive income 1,535 ( 254 ) 1,281 Balance as of December 31, 2023 ( 13,056 ) 1,067 ( 11,989 ) Current period change excluding amounts reclassified from accumulated other comprehensive income (1) ( 3,110 ) 449 ( 2,661 ) Amounts reclassified from accumulated other comprehensive income — 31 31 Total change in accumulated other comprehensive income ( 3,110 ) 480 ( 2,630 ) Balance as of December 31, 2024 ( 16,166 ) 1,547 ( 14,619 ) (1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) net of taxes of $ 196 million and $( 135 ) million in 2024 and 2023, respectively. Amounts Reclassified Out of Accumulated Other Comprehensive Income - Before-tax Income/(Expense) (millions of dollars) 2024 2023 2022 Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) — ( 609 ) — Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense) ( 70 ) ( 81 ) ( 519 ) Income Tax (Expense)/Credit For Components of Other Comprehensive Income (millions of dollars) 2024 2023 2022 Foreign exchange translation adjustment 14 341 54 Postretirement benefits reserves adjustment (excluding amortization) ( 181 ) 200 ( 1,120 ) Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs ( 27 ) ( 20 ) ( 116 ) Total ( 194 ) 521 ( 1,182 ) 88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 5. Cash Flow Information The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents. In 2024, the Corporation completed the acquisition of Pioneer Natural Resources Company (Pioneer) through the issuance of 545 million shares of ExxonMobil common stock having a fair value of $ 63 billion on the acquisition date and assumed debt with a fair value of $ 5 billion. Additional information is provided in Note 21 . In 2023, the Corporation completed the acquisition of Denbury Inc. (Denbury) through the issuance of 46 million shares of ExxonMobil common stock having a fair value of $ 4.8 billion on the acquisition date. Additional information is provided in Note 21 . In 2023, the Corporation completed the sale of Esso Thailand. The sale included cash proceeds as well as cash from debt that was issued to facilitate the sale, which was assumed by the buyer upon closing. For 2024, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts mainly from the sale of upstream assets in the United States, Argentina, and Nigeria . For 2023, the number includes before-tax amounts from the sale of upstream assets in the United States. For 2022, the number includes before-tax amounts from the sale of certain unproved assets in Romania and unconventional assets in Canada and the United States, as well as other smaller divestments. These net (gain)/loss amounts are reported in "Other income" on the Consolidated Statement of Income. (millions of dollars) 2024 2023 2022 Income taxes paid 13,293 15,473 15,364 Cash interest paid Included in cash flows from operating activities 624 584 666 Capitalized, included in cash flows from investing activities 1,276 1,152 838 Total cash interest paid 1,900 1,736 1,504 Note 6. Additional Working Capital Information (millions of dollars) December 31, 2024 December 31, 2023 Notes and accounts receivable Trade, less reserves of $ 162 million and $ 170 million 35,282 30,296 Other, less reserves of $ 314 million and $ 101 million 8,399 7,719 Total 43,681 38,015 Notes and loans payable Bank loans 63 6 Commercial paper — 75 Long-term debt due within one year 4,892 4,009 Total 4,955 4,090 Accounts payable and accrued liabilities Trade payables 36,145 31,249 Payables to equity companies 10,378 11,885 Accrued taxes other than income taxes 3,577 3,817 Other 11,197 11,086 Total 61,297 58,037 Trade notes and accounts receivables include both receivables within the scope of ASC 606 and outside the scope of ASC 606. Receivables outside the scope of ASC 606 primarily relate to physically settled commodity contracts accounted for as derivatives. Credit quality and type of customer are generally similar between receivables within the scope of ASC 606 and those outside it. The Corporation has short-term committed lines of credit of $ 0.2 billion which were unused as of December 31, 2024. These lines of credit are available for general corporate purposes. 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 7. Equity Company Information The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1 ). These companies are primarily engaged in oil and gas exploration and production, natural gas marketing, transportation of crude oil, and petrochemical manufacturing in North America; natural gas production and distribution in Europe; LNG operations in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining and marketing ventures. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 9 percent, 9 percent, and 11 percent in the years 2024, 2023, and 2022, respectively. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences between the Company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned, to the extent practicable, to specific assets and liabilities based on the Company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “Income from equity affiliates” on the Consolidated Statement of Income. Equity Company Financial Summary (millions of dollars) 2024 2023 2022 Total ExxonMobil Share Total ExxonMobil Share Total ExxonMobil Share Total revenues 117,036 35,532 132,783 40,682 183,812 57,528 Income before income taxes 33,357 9,304 35,999 10,078 61,550 19,279 Income taxes 11,434 3,209 11,404 3,085 23,149 7,603 Income from equity affiliates 21,923 6,095 24,595 6,993 38,401 11,676 Current assets 50,779 18,286 53,081 18,713 77,457 24,994 Long-term assets 145,671 39,092 150,198 40,986 153,186 42,921 Total assets 196,450 57,378 203,279 59,699 230,643 67,915 Current liabilities 26,786 8,699 30,721 9,652 53,640 15,555 Long-term liabilities 55,218 16,484 57,237 17,059 62,009 18,929 Net assets 114,446 32,195 115,321 32,988 114,994 33,431 90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A list of significant equity companies as of December 31, 2024, together with the Corporation’s percentage ownership interest, is detailed below: Percentage Ownership Interest Upstream Barzan Gas Company Limited 7 BEB Erdgas und Erdoel GmbH & Co. KG 50 Caspian Pipeline Consortium 8 Coral FLNG S.A. 25 Cross Timbers Energy LLC 50 GasTerra B.V. 25 Golden Pass LNG Terminal LLC 30 Golden Pass Pipeline LLC 30 Marine Well Containment Company LLC 11 Mozambique Rovuma Venture S.p.A. 36 Nederlandse Aardolie Maatschappij B.V. 50 Papua New Guinea Liquefied Natural Gas Global Company LDC 33 Permian Highway Pipeline LLC 17 QatarEnergy LNG N (2) 24 QatarEnergy LNG NFE (3) 25 QatarEnergy LNG S (1) 25 QatarEnergy LNG S (2) 31 QatarEnergy LNG S (3) 30 South Hook LNG Terminal Company Limited 24 Tengizchevroil LLP 25 Energy Products, Chemical Products, and/or Specialty Products Al-Jubail Petrochemical Company 50 Alberta Products Pipe Line Ltd. 45 Fujian Refining & Petrochemical Co. Ltd. 25 Gulf Coast Growth Ventures LLC 50 Infineum USA L.P. 50 Permian Express Partners LLC 12 Saudi Aramco Mobil Refinery Company Ltd. 50 Saudi Yanbu Petrochemical Co. 50 91 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 8. Investments, Advances and Long-Term Receivables (millions of dollars) December 31, 2024 December 31, 2023 Equity method company investments and advances Investments 34,010 34,080 Advances, net of allowances of $ 40 million and $ 33 million 7,084 7,527 Total equity method company investments and advances 41,094 41,607 Equity securities carried at fair value and other investments at adjusted cost basis 343 177 Long-term receivables and miscellaneous, net of reserves of $ 2,433 million and $ 1,966 million 5,763 5,846 Total 47,200 47,630 Note 9. Property, Plant and Equipment and Asset Retirement Obligations Property, Plant and Equipment (millions of dollars) December 31, 2024 December 31, 2023 Cost Net Cost Net Upstream 423,038 226,021 359,031 148,245 Energy Products 58,259 28,349 57,400 27,284 Chemical Products 39,224 19,973 38,801 20,329 Specialty Products 9,559 4,229 9,385 4,378 Other 23,823 15,746 22,768 14,704 Total 553,903 294,318 487,385 214,940 In 2024, the Corporation identified situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable and conducted impairment assessments. Before-tax impairment charges recognized during 2024 are immaterial. In 2023, the Corporation recognized before-tax impairment charges of $ 3.3 billion, in large part due to impairing the idled Upstream Santa Ynez Unit assets and associated facilities in California, reflecting the continuing challenges in the state regulatory environment that impeded progress in restoring operations. Other before-tax impairment charges recognized during 2023 included $ 0.3 billion in Upstream, $ 0.3 billion in Chemical Products, and $ 0.1 billion in Specialty Products. In 2022, the Corporation recognized before-tax impairment charges of $ 4.5 billion as a result of the Corporation's plans to discontinue operations on the Sakhalin-1 project and develop steps to exit the venture in response to Russia's military action in Ukraine (Refer to Note 2 for additional information). Other before-tax impairment charges recognized during 2022 included $ 1.5 billion in Upstream and $ 0.4 billion in Energy Products. Impairment charges are primarily recognized in the lines “ Depreciation and depletion” and “Exploration expenses, including dry holes ” on the Consolidated Statement of Income. Accumulated depreciation and depletion totaled $ 259,585 million at the end of 2024 and $ 272,445 million at the end of 2023. 92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Asset Retirement Obligations The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. Asset retirement obligations incurred in the current period were level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for facilities in the Product Solutions business generally become firm at the time a decision is made to permanently shut down and dismantle the facilities. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites generally have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. The following table summarizes the activity in the liability for asset retirement obligations: (millions of dollars) 2024 2023 2022 Balance at January 1 12,989 10,491 10,630 Accretion expense and other provisions 709 734 744 Reduction due to property sales ( 1,445 ) ( 288 ) ( 328 ) Payments made ( 1,191 ) ( 693 ) ( 518 ) Liabilities incurred 533 831 119 Foreign currency translation ( 447 ) 124 ( 330 ) Revisions 884 1,790 174 Balance at December 31 12,032 12,989 10,491 The long-term Asset Retirement Obligations were $ 10,886 million and $ 11,942 million at December 31, 2024 and 2023, respectively, and are included in “Other long-term obligations” on the Consolidated Balance Sheet. Estimated cash payments in 2025 and 2026 are $ 1,146 million and $ 968 million, respectively. 93 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 10. Accounting for Suspended Exploratory Well Costs The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. The following two tables provide details of the changes in the balance of suspended exploratory well costs, including an aging summary of those costs. Change in capitalized suspended exploratory well costs (millions of dollars) 2024 2023 2022 Balance beginning at January 1 3,559 3,512 4,120 Additions pending the determination of proved reserves 453 200 378 Charged to expense ( 69 ) ( 95 ) ( 259 ) Reclassifications to wells, facilities and equipment based on the determination of proved reserves ( 292 ) ( 142 ) ( 142 ) Divestments/Other ( 51 ) 84 ( 585 ) Ending balance at December 31 3,600 3,559 3,512 Ending balance attributed to equity companies included above 225 306 306 Period-end capitalized suspended exploratory well costs (millions of dollars) 2024 2023 2022 Capitalized for a period of one year or less 453 200 378 Capitalized for a period of between one and five years 583 1,030 969 Capitalized for a period of between five and ten years 1,544 1,411 1,410 Capitalized for a period of greater than ten years 1,020 918 755 Capitalized for a period greater than one year - subtotal 3,147 3,359 3,134 Total 3,600 3,559 3,512 Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with only exploratory well costs capitalized for a period of one year or less and those that have had exploratory well costs capitalized for a period greater than one year. 2024 2023 2022 Number of projects that only have exploratory well costs capitalized for a period of one year or less 5 — 10 Number of projects that have exploratory well costs capitalized for a period greater than one year 24 31 26 Total 29 31 36 Of the 24 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2024, 11 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 13 projects are those with completed exploratory activity. These projects are currently being progressed toward development, including evaluation to tie into existing infrastructure, awaiting capacity and aligning with the respective governments for development plans. 94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 11. Leases The Corporation and its consolidated affiliates generally purchase the property, plant and equipment used in operations, but there are situations where assets are leased, primarily for drilling equipment, tankers, office buildings, railcars, and other moveable equipment. Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for drilling equipment, tankers, and finance leases is excluded from the calculation of right of use assets and lease liabilities. Generally, assets are leased only for a portion of their useful lives and are accounted for as operating leases. In limited situations, assets are leased for nearly all of their useful lives and are accounted for as finance leases. Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. In general, leases are capitalized using the incremental borrowing rate of the leasing affiliate. The Corporation’s activities as a lessor are not significant. Lease Cost (millions of dollars) Operating Leases Finance Leases 2024 2023 2022 2024 2023 2022 Operating lease cost 2,296 1,976 1,776 Short-term and other (net of sublease rental income) 2,047 1,563 1,389 Amortization of right of use assets 140 107 243 Interest on lease liabilities 149 140 210 Total (1) 4,343 3,539 3,165 289 247 453 (1) Includes $ 1,195 million, $ 999 million, and $ 908 million for drilling rigs and related equipment operating leases in 2024, 2023, and 2022, respectively. Balance Sheet (millions of dollars) Operating Leases Finance Leases December 31, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Right of use assets Included in Other assets, including intangibles - net 7,123 6,849 Included in Property, plant and equipment - net 2,888 2,712 Total right of use assets 7,123 6,849 2,888 2,712 Lease liability due within one year Included in Accounts payable and accrued liabilities 1,852 1,617 6 5 Included in Notes and loans payable 117 95 Long-term lease liability Included in Other long-term obligations 4,626 4,393 Included in Long-term debt 2,123 1,821 Included in Long-term obligations to equity companies 115 121 Total lease liability (2) 6,478 6,010 2,361 2,042 Weighted-average remaining lease term (years) 7 8 18 26 Weighted-average discount rate (percent) 4.9 % 3.9 % 6.4 % 7.2 % (2) Includes $ 2,198 million and $ 2,032 million for drilling rigs and related equipment operating leases in 2024 and 2023, respectively. 95 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Maturity Analysis of Lease Liabilities (millions of dollars) Operating Leases Finance Leases December 31, 2024 2025 2,119 275 2026 1,569 274 2027 1,134 265 2028 715 263 2029 305 256 2030 and beyond 1,712 2,450 Total lease payments 7,554 3,783 Discount to present value ( 1,076 ) ( 1,422 ) Total lease liability 6,478 2,361 In addition to the lease liabilities in the table immediately above, at December 31, 2024, undiscounted commitments for leases not yet commenced totaled $ 3,938 million for operating leases and $ 1,957 million for finance leases. Estimated cash payments for operating and finance leases not yet commenced are $ 248 million and $ 341 million for 2025 and 2026, respectively. Operating leases not yet commenced primarily relate to LNG transportation vessels. Finance leases not yet commenced primarily relate to a long-term processing agreement to upgrade residue to hydrogen. The underlying assets are primarily designed by, and are being constructed by, the lessors. Other Information (millions of dollars) Operating Leases Finance Leases 2024 2023 2022 2024 2023 2022 Cash paid for amounts included in the measurement of lease liabilities Cash flows from operating activities 1,301 1,135 1,119 20 20 20 Cash flows from investing activities 837 758 500 Cash flows from financing activities 121 86 149 Noncash right of use assets recorded for lease liabilities In exchange for lease liabilities during the period 2,074 2,161 1,997 109 529 73 Note 12. Earnings Per Share Earnings per common share 2024 2023 2022 Net income (loss) attributable to ExxonMobil (millions of dollars) 33,680 36,010 55,740 Weighted-average number of common shares outstanding (millions of shares) (1) 4,298 4,052 4,205 Earnings (loss) per common share (dollars) (2) 7.84 8.89 13.26 Dividends paid per common share (dollars) 3.84 3.68 3.55 (1) Includes restricted shares not vested as well as 545 million shares issued for the Pioneer acquisition on May 3, 2024. (2) The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown. 96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 13. Financial Instruments and Derivatives The estimated fair value of financial instruments and derivatives at December 31, 2024, and December 31, 2023, and the related hierarchy level for the fair value measurement was as follows: December 31, 2024 Fair Value (millions of dollars) Level 1 Level 2 Level 3 Total Gross Assets & Liabilities Effect of Counterparty Netting Effect of Collateral Netting Difference in Carrying Value and Fair Value Net Carrying Value Assets Derivative assets (1) 3,223 1,206 — 4,429 ( 3,913 ) ( 3 ) — 513 Advances to/receivables from equity companies (2)(6) — 2,466 4,167 6,633 — — 451 7,084 Other long-term financial assets (3) 1,468 — 1,504 2,972 — — 247 3,219 Liabilities Derivative liabilities (4) 3,561 1,416 — 4,977 ( 3,913 ) ( 341 ) — 723 Long-term debt (5) 28,884 1,813 — 30,697 — — 3,935 34,632 Long-term obligations to equity companies (6) — — 1,393 1,393 — — ( 47 ) 1,346 Other long-term financial liabilities (7) — — 583 583 — — 57 640 December 31, 2023 Fair Value (millions of dollars) Level 1 Level 2 Level 3 Total Gross Assets & Liabilities Effect of Counterparty Netting Effect of Collateral Netting Difference in Carrying Value and Fair Value Net Carrying Value Assets Derivative assets (1) 4,544 1,731 — 6,275 ( 5,177 ) ( 528 ) — 570 Advances to/receivables from equity companies (2)(6) — 2,517 4,491 7,008 — — 519 7,527 Other long-term financial assets (3) 1,389 — 944 2,333 — — 202 2,535 Liabilities Derivative liabilities (4) 4,056 1,608 — 5,664 ( 5,177 ) ( 40 ) — 447 Long-term debt (5) 30,556 2,004 — 32,560 — — 3,102 35,662 Long-term obligations to equity companies (6) — — 1,896 1,896 — — ( 92 ) 1,804 Other long-term financial liabilities (7) — — 697 697 — — 45 742 (1) Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net. (2) Included in the Balance Sheet line: Investments, advances and long-term receivables. (3) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles - net. (4) Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations. (5) Excluding finance lease obligations. (6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the equity company. (7) Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on expected drilling activities and discount rates. At December 31, 2024, and December 31, 2023, respectively, the Corporation had $ 491 million and $ 800 million of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements. 97 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. Commodity contracts held for trading purposes are presented in the Consolidated Statement of Income on a net basis in the line “Sales and other operating revenue” and in the Consolidated Statement of Cash Flows in “Cash Flows from Operating Activities”. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2024 and 2023, or results of operations for 2024, 2023, and 2022. During the fourth quarter of 2024, the Corporation initiated a program to hedge certain of its fixed-rate debt instruments against changes in fair value due to changes in the designated benchmark interest rate. This program utilizes fair value hedge accounting. The derivative (hedging) instruments are fixed-for-floating interest rate swaps, with settlement dates that correspond to the interest payments associated with the fixed-rate debt (hedged item). Changes in the fair values of the hedging instruments are perfectly offset by changes in the fair values of the hedged items; the effects of these changes in fair values are recorded in "Interest expense" in the Consolidated Statement of Income. This program was not material to the Consolidated Financial Statements. The Corporation intends to expand the use of this program in future periods. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting, and monitoring of derivative activity. The net notional long/(short) position of derivative instruments at December 31, 2024, and December 31, 2023, was as follows: (millions) December 31, December 31, 2024 2023 Crude oil (barrels) 13 ( 7 ) Petroleum products (barrels) ( 32 ) ( 43 ) Natural gas (MMBTUs) ( 675 ) ( 560 ) Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are included in the following lines on a before-tax basis: (millions of dollars) 2024 2023 2022 Sales and other operating revenue ( 661 ) 986 ( 1,763 ) Crude oil and product purchases 3 79 314 Total ( 658 ) 1,065 ( 1,449 ) Note 14. Long-Term Debt At December 31, 2024, long-term debt consisted of $ 31,340 million due in U.S. dollars and $ 5,415 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $ 4,892 million, which matures within one year and is included in current liabilities. The amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2025, in millions of dollars, are: 2026 – $ 5,456 ; 2027 – $ 1,357 ; 2028 – $ 1,441 ; and 2029 – $ 1,604 . At December 31, 2024, the Corporation's unused long-term lines of credit were $ 1.3 billion. The Corporation may use non-derivative financial instruments, such as its foreign currency-denominated debt, as hedges of its net investments in certain foreign subsidiaries. Under this method, the change in the carrying value of the financial instruments due to foreign exchange fluctuations is reported in accumulated other comprehensive income. As of December 31, 2024, the Corporation has designated its $ 3.1 billion of Euro-denominated debt and related accrued interest as a net investment hedge of its European business. The net investment hedge is deemed to be perfectly effective. 98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Summarized long-term debt at year-end 2024 and 2023 are shown in the table below: (millions of dollars, except where stated otherwise) Average Rate (1) December 31, 2024 December 31, 2023 Exxon Mobil Corporation (2)(3) 2.709 % notes due 2025 — 1,750 2.992 % notes due 2025 — 2,767 3.043 % notes due 2026 2,500 2,500 2.275 % notes due 2026 1,000 1,000 3.294 % notes due 2027 1,000 1,000 2.440 % notes due 2029 1,250 1,250 3.482 % notes due 2030 1,992 2,000 2.610 % notes due 2030 2,000 2,000 2.995 % notes due 2039 750 750 4.227 % notes due 2040 2,076 2,080 3.567 % notes due 2045 1,000 1,000 4.114 % notes due 2046 2,500 2,500 3.095 % notes due 2049 1,500 1,500 4.327 % notes due 2050 2,750 2,750 3.452 % notes due 2051 2,750 2,750 Exxon Mobil Corporation - Euro-denominated 0.524 % notes due 2028 1,039 1,105 0.835 % notes due 2032 1,039 1,105 1.408 % notes due 2039 1,039 1,105 XTO Energy Inc. (4) 6.100 % senior notes due 2036 187 189 6.750 % senior notes due 2037 284 286 6.375 % senior notes due 2038 221 223 Pioneer Natural Resources Company (5) 1.125 % senior notes due 2026 718 — 5.100 % senior notes due 2026 1,097 — 7.200 % senior notes due 2028 250 — 1.900 % senior notes due 2030 931 — 2.150 % senior notes due 2031 846 — Parsley Energy LLC (6) 4.125 % senior notes due 2028 131 — Industrial revenue bonds due 2025-2051 3.149 % 2,032 2,123 Finance leases & other obligations 4.577 % 3,951 3,838 Debt issuance costs ( 78 ) ( 88 ) Total long-term debt 36,755 37,483 (1) Average effective or imputed interest rates at December 31, 2024. (2) Includes impacts of hedge accounting of interest rate swaps. (3) Includes premiums of $ 76 million in 2024 and $ 97 million in 2023. (4) Includes premiums of $ 66 million in 2024 and $ 71 million in 2023. (5) Includes net discounts of $ 348 million in 2024. (6) Includes discounts of $ 7 million in 2024. 99 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 15. Incentive Program The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock, and other forms of awards. Awards may be granted to eligible employees of the Company and those affiliates at least 50 percent owned by the Corporation. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire, or are settled in cash do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the ExxonMobil Board of Directors terminates the plan early. At the end of 2024, remaining shares available for award under the 2003 Incentive Program were 47 million. Restricted Stock and Restricted Stock Units. Awards of restricted (nonvested) common stock units granted under the 2003 Incentive Program totaled 10,393 thousand, 9,701 thousand, and 9,392 thousand in 2024, 2023, and 2022, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities, and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares and units may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares and units in each award vesting after three years , and the remaining 50 percent vesting after seven years . Some management, professional, and technical participants will receive awards that vest in full after three years . Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years for the remaining 50 percent of the award, except that for awards granted prior to 2020 the vesting of the 10 -year portion of the award is delayed until retirement if later than 10 years. In accordance with the terms of the merger agreement for the Pioneer acquisition, which closed on May 3, 2024, awards of Pioneer restricted stock units granted under the Pioneer Amended and Restated 2006 Long Term Incentive Plan (Pioneer LTIP) that did not vest as of immediately prior to the closing were cancelled and converted into awards of ExxonMobil restricted stock units based on the merger exchange ratio. The grant date for the converted Pioneer awards is considered to be the effective date of the acquisition for the purpose of calculating fair value. Compensation costs for the converted Pioneer awards is recognized in income over a period commensurate with the vesting schedule. Pioneer awards vest in three installments over a period of three years with approximately one third of the awards vesting each year. Shares for these awards are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. The maximum term of the Pioneer awards is three years . As of the Pioneer acquisition closing on May 3, 2024, the maximum number of shares of stock that can be issued under the Pioneer LTIP was 9,458 thousand. At the end of 2024, remaining shares available for awards under the Pioneer LTIP were 9,362 thousand. The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2024. Restricted stock and units outstanding 2024 Shares (thousands) Weighted-Average Grant-Date Fair Value per Share (dollars) Issued and outstanding at January 1 37,812 77.94 Awards issued in 2024 10,496 104.21 Vested ( 8,185 ) 74.55 Forfeited ( 528 ) 101.66 Issued and outstanding at December 31 39,595 85.29 Impacts of Pioneer awards incorporated in the totals above include 760 thousand awards issued in 2024, ( 67 ) thousand vested and ( 209 ) thousand forfeited. Value of restricted stock units 2024 2023 2022 Grant price (dollars) 118.57 103.16 110.46 Value at date of grant: (millions of dollars) Units settled in stock 1,193 900 931 Units settled in cash 129 101 106 Total value 1,322 1,001 1,037 100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2024, there was $ 2,588 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.6 years. The compensation cost charged against income for the restricted stock and restricted stock units was $ 835 million, $ 611 million, and $ 648 million for 2024, 2023, and 2022, respectively. The income tax benefit recognized in income related to this compensation expense was $ 73 million, $ 50 million, and $ 52 million for the same periods, respectively. The fair value of shares and units vested in 2024, 2023, and 2022 was $ 980 million, $ 892 million, and $ 1,027 million, respectively. Cash payments of $ 87 million, $ 79 million, and $ 89 million for vested restricted stock units settled in cash were made in 2024, 2023, and 2022, respectively. Note 16. Litigation and Other Contingencies Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. State and local governments and other entities in various jurisdictions across the United States and its territories have filed a number of legal proceedings against several oil and gas companies, including ExxonMobil, requesting unprecedented legal and equitable relief for various alleged injuries purportedly connected to climate change. These lawsuits assert a variety of novel, untested claims under statutory and common law. Additional such lawsuits may be filed. We believe the legal and factual theories set forth in these proceedings are meritless and represent an inappropriate attempt to use the court system to usurp the proper role of policymakers in addressing the societal challenges of climate change. Local governments in Louisiana have filed unprecedented legal proceedings against a number of oil and gas companies, including ExxonMobil, requesting compensation for the restoration of coastal marsh erosion in the state. We believe the factual and legal theories set forth in these proceedings are meritless. While the outcome of any litigation can be unpredictable, we believe the likelihood is remote that the ultimate outcomes of these lawsuits will have a material adverse effect on the Corporation’s operations, financial condition, or financial statements taken as a whole. We will continue to defend vigorously against these claims. Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2024, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. Where it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence. December 31, 2024 (millions of dollars) Equity Company Obligations (1) Other Third-Party Obligations Total Guarantees Debt-related 1,073 167 1,240 Other 678 5,965 6,643 Total 1,751 6,132 7,883 (1) ExxonMobil share. Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. 101 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 17. Pension and Other Postretirement Benefits The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31. Pension Benefits Other Postretirement Benefits (millions of dollars, except where stated otherwise) U.S. Non-U.S. 2024 2023 2024 2023 2024 2023 Weighted-average assumptions used to determine benefit obligations at December 31 Discount rate (percent) 5.70 5.30 4.60 4.30 5.80 5.30 Long-term rate of compensation increase (percent) 4.00 4.50 4.20 4.50 4.00 4.50 Change in benefit obligation Benefit obligation at January 1 13,143 12,350 21,327 19,342 5,014 5,211 Service cost 499 466 338 323 81 78 Interest cost 671 664 823 922 250 276 Actuarial loss/(gain) (1) ( 441 ) 550 ( 658 ) 1,393 ( 81 ) 176 Benefits paid (2)(3) ( 874 ) ( 870 ) ( 1,240 ) ( 1,214 ) ( 534 ) ( 545 ) Foreign exchange rate changes — — ( 1,274 ) 515 ( 40 ) 11 Amendments, divestments and other 1 ( 17 ) ( 118 ) 46 101 ( 193 ) Benefit obligation at December 31 12,999 13,143 19,198 21,327 4,791 5,014 Accumulated benefit obligation at December 31 11,227 11,033 17,818 19,769 — — (1) Actuarial loss/(gain) primarily reflects higher discount rates. (2) Benefit payments for funded and unfunded plans. (3) For 2024 and 2023, other postretirement benefits paid are net of $ 10 million and $ 19 million of Medicare subsidy receipts, respectively. For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.0 percent in 2026 and subsequent years. Pension Benefits Other Postretirement Benefits (millions of dollars) U.S. Non-U.S. 2024 2023 2024 2023 2024 2023 Change in plan assets Fair value at January 1 11,367 10,989 18,431 16,757 371 348 Actual return on plan assets 286 1,121 862 1,484 20 36 Foreign exchange rate changes — — ( 1,051 ) 492 — — Company contribution 300 — 288 615 24 38 Benefits paid (1) ( 709 ) ( 743 ) ( 931 ) ( 878 ) ( 51 ) ( 51 ) Other — — ( 221 ) ( 39 ) — — Fair value at December 31 11,244 11,367 17,378 18,431 364 371 (1) Benefit payments for funded plans. 102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local applicable tax rules and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate. Pension Benefits (millions of dollars) U.S. Non-U.S. 2024 2023 2024 2023 Assets in excess of/(less than) benefit obligation Balance at December 31 Funded plans ( 267 ) ( 271 ) 1,679 1,028 Unfunded plans ( 1,488 ) ( 1,505 ) ( 3,499 ) ( 3,924 ) Total ( 1,755 ) ( 1,776 ) ( 1,820 ) ( 2,896 ) The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its Consolidated Balance Sheet and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income. Pension Benefits Other Postretirement Benefits (millions of dollars) U.S. Non-U.S. 2024 2023 2024 2023 2024 2023 Assets in excess of/(less than) benefit obligation Balance at December 31 (1) ( 1,755 ) ( 1,776 ) ( 1,820 ) ( 2,896 ) ( 4,427 ) ( 4,643 ) Amounts recorded in the Consolidated Balance Sheet consist of: Other assets 2 — 2,399 1,895 — — Current liabilities ( 213 ) ( 201 ) ( 207 ) ( 225 ) ( 283 ) ( 288 ) Postretirement benefits reserves ( 1,544 ) ( 1,575 ) ( 4,012 ) ( 4,566 ) ( 4,144 ) ( 4,355 ) Total recorded ( 1,755 ) ( 1,776 ) ( 1,820 ) ( 2,896 ) ( 4,427 ) ( 4,643 ) Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss/(gain) 631 744 557 1,364 ( 1,421 ) ( 1,453 ) Prior service cost ( 252 ) ( 283 ) 420 401 ( 405 ) ( 459 ) Total recorded in accumulated other comprehensive income 379 461 977 1,765 ( 1,826 ) ( 1,912 ) (1) Fair value of assets less benefit obligation shown on the preceding page. 103 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted-average of the target asset allocation percentages and the long-term return assumption for each asset class. Pension Benefits Other Postretirement Benefits (millions of dollars, except where stated otherwise) U.S. Non-U.S. 2024 2023 2022 2024 2023 2022 2024 2023 2022 Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 Discount rate (percent) 5.30 5.60 3.00 4.30 4.90 2.20 5.30 5.60 3.10 Long-term rate of return on funded assets (percent) 6.80 5.20 4.60 5.50 4.20 3.50 6.00 4.70 3.80 Long-term rate of compensation increase (percent) 4.50 4.50 4.50 4.50 5.20 4.20 4.50 4.50 4.50 Components of net periodic benefit cost Service cost 499 466 712 338 323 570 81 78 138 Interest cost 671 664 518 823 922 614 250 276 216 Expected return on plan assets ( 724 ) ( 532 ) ( 560 ) ( 955 ) ( 688 ) ( 815 ) ( 20 ) ( 14 ) ( 14 ) Amortization of actuarial loss/(gain) 83 85 156 97 108 180 ( 103 ) ( 122 ) 6 Amortization of prior service cost ( 31 ) ( 29 ) ( 29 ) 50 52 43 ( 63 ) ( 42 ) ( 42 ) Net pension enhancement and curtailment/settlement cost 27 29 205 16 5 4 — — — Net periodic benefit cost 525 683 1,002 369 722 596 145 176 304 Changes in amounts recorded in accumulated other comprehensive income: Net actuarial loss/(gain) ( 3 ) ( 39 ) ( 607 ) ( 611 ) 602 ( 1,641 ) ( 81 ) 154 ( 1,910 ) Amortization of actuarial (loss)/gain ( 110 ) ( 114 ) ( 361 ) ( 112 ) ( 108 ) ( 183 ) 103 122 ( 6 ) Prior service cost/(credit) — ( 17 ) — 81 153 84 ( 8 ) ( 312 ) — Amortization of prior service (cost)/credit 31 29 29 ( 44 ) ( 52 ) ( 40 ) 63 42 42 Foreign exchange rate changes — — — ( 102 ) 46 ( 199 ) 9 ( 2 ) ( 7 ) Total recorded in other comprehensive income ( 82 ) ( 141 ) ( 939 ) ( 788 ) 641 ( 1,979 ) 86 4 ( 1,881 ) Total recorded in net periodic benefit cost and other comprehensive income, before tax 443 542 63 ( 419 ) 1,363 ( 1,383 ) 231 180 ( 1,577 ) Costs for defined contribution plans were $ 415 million, $ 383 million, and $ 365 million in 2024, 2023, and 2022, respectively. 104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the change in accumulated other comprehensive income is shown in the table below: Total Pension and Other Postretirement Benefits (millions of dollars) 2024 2023 2022 (Charge)/credit to other comprehensive income, before tax U.S. pension 82 141 939 Non-U.S. pension 788 ( 641 ) 1,979 Other postretirement benefits ( 86 ) ( 4 ) 1,881 Total (charge)/credit to other comprehensive income, before tax 784 ( 504 ) 4,799 (Charge)/credit to income tax (see Note 4 ) ( 208 ) 180 ( 1,236 ) (Charge)/credit to investment in equity companies 24 16 235 (Charge)/credit to other comprehensive income including noncontrolling interests, after tax 600 ( 308 ) 3,798 Charge/(credit) to equity of noncontrolling interests ( 120 ) 54 ( 212 ) (Charge)/credit to other comprehensive income attributable to ExxonMobil 480 ( 254 ) 3,586 The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities, and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive global equity and local currency fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in investment-grade corporate and government debt securities with interest rate sensitivity designed to approximate the interest rate sensitivity of plan liabilities. Target asset allocations for benefit plans are reviewed periodically and set based on considerations such as risk, diversification, liquidity, and funding level. The target asset allocations for the major benefit plans range from 15 to 40 percent in equity securities and the remainder in fixed income securities. The equity allocation for the U.S. plan includes a target allocation of 10 percent to limited partnerships that focus on the venture capital, growth and buyout sectors of the private equity market. Certain non-U.S. plans include small allocations to private equity partnerships that primarily focus on early-stage venture capital. The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment. 105 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2024 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below: U.S. Pension Non-U.S. Pension (millions of dollars) Fair Value Measurement at December 31, 2024, Using: Fair Value Measurement at December 31, 2024, Using: Level 1 Level 2 Level 3 Net Asset Value Total Level 1 Level 2 Level 3 Net Asset Value Total Asset category: Equity securities U.S. — — — 2,263 2,263 — — — 2,865 2,865 Non-U.S. — — — 1,225 1,225 43 (1) — — 1,560 1,603 Private equity — — — 439 439 — — — 291 291 Debt securities Corporate — 971 (2) — 4,498 5,469 — 49 (2) — 3,650 3,699 Government — 592 (2) — 1,126 1,718 77 (3) 141 (2) — 8,222 8,440 Asset-backed — — — 1 1 — 12 (2) — 180 192 Other — — — — — — — — 13 13 Real Estate — — — — — — — — 107 107 Cash — — — 113 113 78 6 (4) — 69 153 Other — 14 — — 14 — — — — — Total at fair value — 1,577 — 9,665 11,242 198 208 — 16,957 17,363 Insurance contracts at contract value 2 15 Total plan assets 11,244 17,378 (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. (3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. (4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a level 2 input. Other Postretirement (millions of dollars) Fair Value Measurement at December 31, 2024, Using: Level 1 Level 2 Level 3 Net Asset Value Total Asset category: Equity securities U.S. 92 (1) — — — 92 Non-U.S. 36 (1) — — — 36 Debt securities Corporate — 57 (2) — — 57 Government — 174 (2) — — 174 Asset-backed — 3 (2) — — 3 Cash — 2 — — 2 Total at fair value 128 236 — — 364 (1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. 106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2023 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below: U.S. Pension Non-U.S. Pension (millions of dollars) Fair Value Measurement at December 31, 2023, Using: Fair Value Measurement at December 31, 2023, Using: Level 1 Level 2 Level 3 Net Asset Value Total Level 1 Level 2 Level 3 Net Asset Value Total Asset category: Equity securities U.S. — — — 2,114 2,114 — — — 2,642 2,642 Non-U.S. — — — 1,344 1,344 52 (1) — — 1,688 1,740 Private equity — — — 375 375 — — — 294 294 Debt securities Corporate — 4,699 (2) — 1 4,700 — 61 (2) — 4,370 4,431 Government — 2,650 (2) — 2 2,652 134 (3) 171 (2) — 8,429 8,734 Asset-backed — — — 1 1 — 22 (2) — 221 243 Other — — — — — — — — 4 4 Real Estate — — — — — — — — 70 70 Cash — — — 178 178 189 17 (4) — 45 251 Total at fair value — 7,349 — 4,015 11,364 375 271 — 17,763 18,409 Insurance contracts at contract value 3 22 Total plan assets 11,367 18,431 (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. (3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. (4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a level 2 input. Other Postretirement (millions of dollars) Fair Value Measurement at December 31, 2023, Using: Level 1 Level 2 Level 3 Net Asset Value Total Asset category: Equity securities U.S. 84 (1) — — — 84 Non-U.S. 40 (1) — — — 40 Debt securities Corporate — 61 (2) — — 61 Government — 182 (2) — — 182 Asset-backed — 3 (2) — — 3 Cash — 1 — — 1 Total at fair value 124 247 — — 371 (1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. 107 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of pension plans with an accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below: Pension Benefits (millions of dollars) U.S. Non-U.S. 2024 2023 2024 2023 For funded pension plans with an accumulated benefit obligation in excess of plan assets: Accumulated benefit obligation — — 1,025 1,145 Fair value of plan assets — — 574 562 For funded pension plans with a projected benefit obligation in excess of plan assets: Projected benefit obligation 11,501 11,638 1,982 2,334 Fair value of plan assets 11,232 11,367 1,261 1,465 For unfunded pension plans: Projected benefit obligation 1,488 1,505 3,499 3,924 Accumulated benefit obligation 1,229 1,173 3,224 3,592 All other postretirement benefit plans are unfunded or underfunded. Pension Benefits Other Postretirement Benefits (millions of dollars) U.S. Non-U.S. Gross Medicare Subsidy Receipt Contributions expected in 2025 — 325 — — Benefit payments expected in: 2025 1,104 1,101 356 1 2026 1,109 1,077 349 1 2027 1,102 1,110 346 1 2028 1,119 1,146 344 1 2029 1,133 1,131 343 1 2030 - 2034 5,854 5,681 1,752 3 Note 18. Disclosures about Segments and Related Information Our reportable segments are Upstream, Energy Products, Chemical Products, and Specialty Products. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and reflect the nature of internal reviews by our Management Committee (MC). The MC is considered collectively, and not in their individual capacity, to be our Chief Operating Decision Maker (CODM), and includes our CEO, CFO, and two Senior Vice Presidents serving as contact executives overseeing the Upstream and Product Solutions businesses. The Upstream segment is organized to explore for and produce crude oil and natural gas. Product Solutions consists of the Energy Products, Chemical Products, and Specialty Products segments, which are organized to manufacture and sell petroleum products and petrochemicals. • Energy Products: Fuels, aromatics, and catalysts and licensing • Chemical Products: Olefins, polyolefins, and intermediates • Specialty Products: Finished lubricants, basestocks and waxes, synthetics, and elastomers and resins The CODM generally allocates resources through an annual planning process. They also allocate capital based on detailed project economics and long-term strategic objectives across reportable segments. The CODM primarily uses changes in Net income (loss) attributable to ExxonMobil to assess segment financial performance. Net income (loss) attributable to ExxonMobil includes transfers at estimated market prices. In Corporate and Financing, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $ 437 million in 2024, $ 234 million in 2023, and $ 117 million in 2022. 108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2024 Revenues and other income Sales and other operating revenue 22,929 14,202 101,325 159,531 8,558 14,338 5,790 12,463 339,136 Income from equity affiliates ( 36 ) 5,649 140 ( 109 ) 166 615 — ( 26 ) 6,399 Intersegment revenue 24,633 41,809 23,626 26,034 7,329 3,893 2,462 573 130,359 Other income 890 670 295 192 5 7 22 116 2,197 Segment revenues and other income 48,416 62,330 125,386 185,648 16,058 18,853 8,274 13,126 478,091 Costs and other items Crude oil and product purchases 18,325 10,388 110,205 153,811 8,510 12,621 4,160 8,753 326,773 Operating expenses, excl. depreciation and depletion (1) 9,822 10,695 8,034 8,924 4,781 4,419 1,931 2,316 50,922 Depreciation and depletion (includes impairments) 11,510 8,014 799 734 611 485 104 133 22,390 Interest expense 185 82 9 10 1 1 — 3 291 Other taxes and duties 334 2,750 3,421 19,699 68 78 7 185 26,542 Total costs and other deductions 40,176 31,929 122,468 183,178 13,971 17,604 6,202 11,390 426,918 Segment income (loss) before income taxes 8,240 30,401 2,918 2,470 2,087 1,249 2,072 1,736 51,173 Income tax expense (benefit) 1,814 10,622 631 164 460 262 494 243 14,690 Segment net income (loss) incl. noncontrolling interests 6,426 19,779 2,287 2,306 1,627 987 1,578 1,493 36,483 Net income (loss) attributable to noncontrolling interests — 815 188 372 — 37 2 17 1,431 Segment net income (loss) 6,426 18,964 2,099 1,934 1,627 950 1,576 1,476 35,052 Reconciliation of consolidated revenues Segment revenues and other income 478,091 Other revenues (2) 1,853 Elimination of intersegment revenues ( 130,359 ) Total consolidated revenues and other income 349,585 Reconciliation of income (loss) attributable to ExxonMobil Total segment net income (loss) 35,052 Corporate and Financing income (loss) ( 1,372 ) Net income (loss) attributable to ExxonMobil 33,680 (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2024 Additions to property, plant and equipment (3) 94,649 8,371 589 1,450 474 1,161 230 227 107,151 Investments in equity companies 4,884 21,396 444 915 3,016 2,649 — 814 34,118 Total assets 154,914 134,609 32,143 43,399 17,445 17,692 2,882 8,040 411,124 Reconciliation to Corporate Total Segment Total Corporate and Financing Corporate Total Additions to property, plant and equipment (3) 107,151 2,181 109,332 Investments in equity companies 34,118 ( 108 ) 34,010 Total assets 411,124 42,351 453,475 (1) Operating expenses, excl. depreciation and depletion includes the following GAAP line items, as reflected on the Income Statement: Production and manufacturing expenses; Selling, general and administrative expenses; Exploration expenses, including dry holes; and Non-service pension and postretirement benefit expense. (2) Primarily Corporate and Financing Interest revenue of $ 1,600 million. (3) Includes non-cash additions. See Note 21 for additions resulting from the Pioneer acquisition in 2024. Due to rounding, numbers presented may not add up precisely to the totals indicated. 109 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2023 Revenues and other income Sales and other operating revenue 9,500 16,074 103,868 164,515 7,951 14,314 6,044 12,363 334,629 Income from equity affiliates 63 5,550 140 131 126 761 — ( 25 ) 6,746 Intersegment revenue 20,971 38,982 23,481 28,258 7,991 3,643 2,570 555 126,451 Other income 631 466 183 87 6 12 19 139 1,543 Segment revenues and other income 31,165 61,072 127,672 192,991 16,074 18,730 8,633 13,032 469,369 Costs and other items Crude oil and product purchases 9,945 11,279 107,796 152,487 8,824 13,096 4,718 8,955 317,100 Operating expenses, excl. depreciation and depletion (1) 6,696 10,960 7,851 9,434 4,560 4,643 1,822 2,238 48,204 Depreciation and depletion (includes impairments) 8,863 7,737 765 797 605 706 93 222 19,788 Interest expense 82 74 4 7 2 2 — 2 173 Other taxes and duties 361 2,684 3,421 22,226 61 78 6 174 29,011 Total costs and other deductions 25,947 32,734 119,837 184,951 14,052 18,525 6,639 11,591 414,276 Segment income (loss) before income taxes 5,218 28,338 7,835 8,040 2,022 205 1,994 1,441 55,093 Income tax expense (benefit) 1,016 10,593 1,543 1,492 396 158 458 235 15,891 Segment net income (loss) incl. noncontrolling interests 4,202 17,745 6,292 6,548 1,626 47 1,536 1,206 39,202 Net income (loss) attributable to noncontrolling interests — 639 169 529 — 36 — 28 1,401 Segment net income (loss) 4,202 17,106 6,123 6,019 1,626 11 1,536 1,178 37,801 Reconciliation of consolidated revenues Segment revenues and other income 469,369 Other revenues (2) 1,664 Elimination of intersegment revenues ( 126,451 ) Total consolidated revenues and other income 344,582 Reconciliation of income (loss) attributable to ExxonMobil Total segment net income (loss) 37,801 Corporate and Financing income (loss) ( 1,791 ) Net income (loss) attributable to ExxonMobil 36,010 (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2023 Additions to property, plant and equipment (3) 10,372 8,217 1,106 1,455 600 1,775 81 370 23,976 Investments in equity companies 4,436 21,485 406 1,135 3,086 2,700 — 952 34,200 Total assets 67,452 138,914 32,123 42,337 17,599 17,076 2,620 8,379 326,500 Reconciliation to Corporate Total Segment Total Corporate and Financing Corporate Total Additions to property, plant and equipment (3) 23,976 5,062 29,038 Investments in equity companies 34,200 ( 120 ) 34,080 Total assets 326,500 49,817 376,317 (1) Operating expenses, excl. depreciation and depletion includes the following GAAP line items, as reflected on the Income Statement: Production and manufacturing expenses; Selling, general and administrative expenses; Exploration expenses, including dry holes; and Non-service pension and postretirement benefit expense. (2) Primarily Corporate and Financing Interest revenue of $ 1,628 million. (3) Includes non-cash additions. Due to rounding, numbers presented may not add up precisely to the totals indicated. 110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2022 Revenues and other income Sales and other operating revenue 14,579 30,585 117,824 188,153 10,670 16,949 6,152 13,727 398,639 Income from equity affiliates 411 10,133 126 322 91 771 — ( 23 ) 11,831 Intersegment revenue 25,658 46,076 29,001 36,894 9,081 5,201 2,587 825 155,323 Other income 449 1,504 184 208 39 30 25 112 2,551 Segment revenues and other income 41,097 88,298 147,135 225,577 19,881 22,951 8,764 14,641 568,344 Costs and other items Crude oil and product purchases 12,786 20,770 123,675 182,293 11,551 15,847 5,112 10,384 382,418 Operating expenses, excl. depreciation and depletion (1) 6,693 12,723 8,373 12,092 4,900 5,022 2,028 2,388 54,219 Depreciation and depletion (includes impairments) 5,791 14,013 741 1,246 542 446 95 193 23,067 Interest expense 51 38 1 7 — 1 — 1 99 Other taxes and duties 718 3,559 3,306 20,040 40 79 5 172 27,919 Total costs and other deductions 26,039 51,103 136,096 215,678 17,033 21,395 7,240 13,138 487,722 Segment income (loss) before income taxes 15,058 37,195 11,039 9,899 2,848 1,556 1,524 1,503 80,622 Income tax expense (benefit) 3,330 11,575 2,615 2,420 520 292 334 252 21,338 Segment net income (loss) incl. noncontrolling interests 11,728 25,620 8,424 7,479 2,328 1,264 1,190 1,251 59,284 Net income (loss) attributable to noncontrolling interests — 869 84 853 — 49 — 26 1,881 Segment net income (loss) 11,728 24,751 8,340 6,626 2,328 1,215 1,190 1,225 57,403 Reconciliation of consolidated revenues Segment revenues and other income 568,344 Other revenues (2) 659 Elimination of intersegment revenues ( 155,323 ) Total consolidated revenues and other income 413,680 Reconciliation of income (loss) attributable to ExxonMobil Total segment net income (loss) 57,403 Corporate and Financing income (loss) ( 1,663 ) Net income (loss) attributable to ExxonMobil 55,740 (millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. As of December 31, 2022 Additions to property, plant and equipment (3) 5,940 6,441 1,141 964 1,026 1,692 37 200 17,441 Investments in equity companies 4,893 21,502 368 1,154 3,124 2,417 — 1,177 34,635 Total assets 66,695 139,764 31,729 41,836 17,342 15,875 2,839 8,316 324,396 Reconciliation to Corporate Total Segment Total Corporate and Financing Corporate Total Additions to property, plant and equipment (3) 17,441 897 18,338 Investments in equity companies 34,635 ( 113 ) 34,522 Total assets 324,396 44,671 369,067 (1) Operating expenses, excl. depreciation and depletion includes the following GAAP line items, as reflected on the Income Statement: Production and manufacturing expenses; Selling, general and administrative expenses; Exploration expenses, including dry holes; and Non-service pension and postretirement benefit expense. (2) Primarily Corporate and Financing Interest revenue of $ 446 million. (3) Includes non-cash additions. Due to rounding, numbers presented may not add up precisely to the totals indicated. 111 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Revenue from Contracts with Customers Sales and other operating revenue include both revenue within the scope of ASC 606 and outside the scope of ASC 606. Revenue outside the scope of ASC 606 primarily relates to physically settled commodity contracts accounted for as derivatives. Contractual terms, credit quality, and type of customer are generally similar between contracts within the scope of ASC 606 and those outside it. Sales and other operating revenue (millions of dollars) 2024 2023 2022 Revenue from contracts with customers 245,143 256,455 304,758 Revenue outside the scope of ASC 606 94,104 78,242 93,917 Total 339,247 334,697 398,675 Geographic Sales and other operating revenue (millions of dollars) 2024 2023 2022 United States 138,657 127,374 149,225 Non-U.S. 200,590 207,323 249,450 Total 339,247 334,697 398,675 Significant non-U.S. revenue sources include: (1) Canada 29,746 28,994 32,970 United Kingdom 20,580 23,372 33,988 Singapore 15,724 15,331 19,029 France 13,743 14,803 17,727 (1) Revenue is determined by primary country of operations. Excludes certain sales and other operating revenues in Non-U.S. operations where attribution to a specific country is not practicable. Long-lived assets (millions of dollars) December 31, 2024 2023 2022 United States 178,633 95,792 90,051 Non-U.S. 115,685 119,148 114,641 Total 294,318 214,940 204,692 Significant non-U.S. long-lived assets include: Canada 28,761 31,682 31,106 Singapore 12,621 12,490 11,972 Guyana 12,414 9,689 6,766 Australia 9,818 11,212 11,372 112 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 19. Income and Other Taxes (millions of dollars) 2024 2023 2022 U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Income tax expense (benefit) Federal and non-U.S. Current 2,061 11,940 14,001 1,987 12,111 14,098 696 15,071 15,767 Deferred - net ( 318 ) ( 512 ) ( 830 ) 463 481 944 4,122 ( 539 ) 3,583 U.S. tax on non-U.S. operations 241 — 241 315 — 315 65 — 65 Total federal and non-U.S. 1,984 11,428 13,412 2,765 12,592 15,357 4,883 14,532 19,415 State 398 — 398 72 — 72 761 — 761 Total income tax expense (benefit) 2,382 11,428 13,810 2,837 12,592 15,429 5,644 14,532 20,176 All other taxes and duties Other taxes and duties 3,849 22,439 26,288 3,871 25,140 29,011 4,087 23,832 27,919 Included in production and manufacturing expenses 2,510 652 3,162 1,961 726 2,687 2,204 862 3,066 Included in SG&A expenses 179 265 444 183 310 493 151 319 470 Total other taxes and duties 6,538 23,356 29,894 6,015 26,176 32,191 6,442 25,013 31,455 Total 8,920 34,784 43,704 8,852 38,768 47,620 12,086 39,545 51,631 The above provisions for deferred income taxes include net benefits of $ 28 million in 2024, and net expenses of $ 24 million and $ 30 million in 2023 and 2022, respectively, related to changes in tax laws and rates. Additional European Taxes on the Energy Sector. On October 6, 2022, European Union (“EU”) Member States adopted an EU Council Regulation which, along with other measures, introduced a new tax described as an emergency intervention to address high energy prices. This regulation imposed a mandatory tax on certain companies active in the crude petroleum, coal, natural gas, and refinery sectors. The regulation required EU Member States to levy a minimum 33 percent tax on in-scope companies’ 2022 and/or 2023 “surplus profits", defined in the regulation as taxable profits exceeding 120 percent of the annual average profits during the 2018-2021 period. EU Member States were required to implement the tax, or an equivalent national measure, by December 31, 2022. The enactment of these regulations by EU Member States resulted in an after-tax charge of approximately $ 1.8 billion to the Corporation’s fourth-quarter 2022 results and approximately $ 0.2 billion in 2023, mainly reflected in the line “Income tax expense (benefit)” on the Consolidated Statement of Income. 113 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2024, 2023, and 2022 is as follows: (millions of dollars) 2024 2023 2022 Income (loss) before income taxes United States 12,258 14,786 28,281 Non-U.S. 36,615 37,997 49,472 Total 48,873 52,783 77,753 Theoretical tax 10,263 11,084 16,328 Effect of equity method of accounting ( 1,301 ) ( 1,341 ) ( 2,407 ) Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1) 4,986 5,888 6,423 State taxes, net of federal tax benefit 314 57 601 Other ( 452 ) ( 259 ) ( 769 ) Total income tax expense (credit) 13,810 15,429 20,176 Effective tax rate calculation Income tax expense (credit) 13,810 15,429 20,176 ExxonMobil share of equity company income taxes 3,197 3,058 7,594 Total income tax expense (credit) 17,007 18,487 27,770 Net income (loss) including noncontrolling interests 35,063 37,354 57,577 Total income (loss) before taxes 52,070 55,841 85,347 Effective income tax rate 33 % 33 % 33 % (1) Includes the impact of the additional European taxes on the energy sector of $ 115 million and $ 1,825 million in 2023 and 2022, respectively. 114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities/(assets) are comprised of the following at December 31: Tax effects of temporary differences for: (millions of dollars) 2024 2023 Property, plant and equipment 40,881 26,627 Other liabilities 8,113 7,534 Total deferred tax liabilities 48,994 34,161 Pension and other postretirement benefits ( 1,365 ) ( 1,777 ) Asset retirement obligations ( 3,156 ) ( 3,532 ) Tax loss carryforwards ( 4,575 ) ( 4,317 ) Other assets ( 7,308 ) ( 6,361 ) Total deferred tax assets ( 16,404 ) ( 15,987 ) Asset valuation allowances 2,516 2,641 Net deferred tax liabilities 35,106 20,815 In 2024, asset valuation allowances of $ 2,516 million decreased by $ 125 million and included net provisions of $ 41 million and foreign currency and other net benefits of $ 166 million. Balance sheet classification (millions of dollars) 2024 2023 Other assets, including intangibles, net ( 3,936 ) ( 3,637 ) Deferred income tax liabilities 39,042 24,452 Net deferred tax liabilities 35,106 20,815 The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2024, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material. 115 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits: Gross unrecognized tax benefits (millions of dollars) 2024 2023 2022 Balance at January 1 3,935 3,398 9,130 Additions based on current year's tax positions 376 350 539 Additions for prior years' tax positions 103 400 294 Reductions for prior years' tax positions ( 293 ) ( 38 ) ( 6,243 ) Reductions due to lapse of the statute of limitations ( 17 ) ( 25 ) ( 16 ) Settlements with tax authorities ( 13 ) ( 153 ) ( 277 ) Foreign exchange effects/other ( 56 ) 3 ( 29 ) Balance at December 31 4,035 3,935 3,398 The gross unrecognized tax benefit balances shown above predominantly relate to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2024, 2023, and 2022 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income. Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation may take many years to complete. It is difficult to predict the timing of resolution for these tax positions since the timing is not entirely within the control of the Corporation. Unlike 2022, during which litigation resolved certain unrecognized tax benefit positions, there was no major resolution of unrecognized tax benefit positions in 2023 or 2024. The Corporation has various U.S. federal income tax positions at issue with the Internal Revenue Service for tax years beginning with 2010. Unfavorable resolution of these issues would not have a materially adverse effect on the Corporation’s net income or liquidity. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent or decrease by up to 30 percent in the next 12 months. The following table summarizes the tax years that remain subject to examination by major tax jurisdiction: Country of Operation Open Tax Years Canada 2001 — 2024 Kazakhstan 2015 — 2024 Nigeria 2017 — 2024 Papua New Guinea 2008 — 2024 United Arab Emirates 2024 United States 2010 — 2024 The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense. For 2024, 2023, and 2022, the Corporation's net interest expense on income tax reserves was $ 142 million, $ 60 million, and $ 16 million, respectively. The related interest payable balances were $ 275 million and $ 134 million at December 31, 2024 and 2023, respectively. 116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 20. Divestment Activities In 2024, the Corporation realized proceeds of approximately $ 5.0 billion and recognized net after-tax earnings of approximately $ 1.0 billion from its divestment activities. This included the sale of the Santa Ynez Unit and associated facilities in California, Mobil Producing Nigeria Unlimited, ExxonMobil Exploration Argentina, the Fos-sur-Mer Refinery (France), the Adriatic LNG terminal (Italy), and certain conventional and unconventional assets in the United States, as well as other smaller divestments. In 2023, the Corporation realized proceeds of approximately $ 4.1 billion and recognized net after-tax earnings of approximately $ 0.6 billion from its divestment activities. This included the sale of the Aera Energy joint venture, Esso Thailand Ltd., the Billings Refinery, certain unconventional assets in the United States, as well as other smaller divestments. In 2022, the Corporation realized proceeds of approximately $ 5.2 billion and recognized net after-tax earnings of approximately $ 0.4 billion from its divestment activities. This included the sale of certain unproved assets in Romania and unconventional assets in Canada and the United States, as well as other smaller divestments. 117 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 21. Mergers and Acquisitions Pioneer Natural Resources Company On May 3, 2024, the Corporation acquired Pioneer, an independent oil and gas exploration and production company. In connection with the acquisition, we issued 545 million shares of ExxonMobil common stock having a fair value of $ 63 billion on the acquisition date, and assumed debt with a fair value of $ 5 billion. The transaction was accounted for as a business combination in accordance with ASC 805, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the provisional fair values of the assets acquired and liabilities assumed. (billions of dollars) Pioneer Current assets (1) 3 Other non-current assets 1 Property, plant & equipment (2) 84 Total identifiable assets acquired 88 Current liabilities (1) 3 Long-term debt (3) 5 Deferred income tax liabilities (4) 16 Other non-current liabilities 2 Total liabilities assumed 26 Net identifiable assets acquired 62 Goodwill (5) 1 Net assets (6) 63 (1) Current assets and current liabilities consist primarily of accounts receivable and payable, with their respective fair values approximating historical values given their short-term duration, expectation of insignificant bad debt expense, and our credit rating. (2) Property, plant and equipment, of which a significant portion relates to crude oil and natural gas properties, was primarily valued using the income approach. Significant inputs and assumptions used in the income approach included estimates for commodity prices, future oil and gas production volumes, drilling and development costs, and risk-adjusted discount rates. Collectively, these inputs are level 3 inputs. (3) Long-term debt was valued using market prices as of the acquisition date, which reflects the use of level 1 inputs. (4) Deferred income taxes represent the tax effects of differences in the tax basis and acquisition date fair values of assets acquired and liabilities assumed. (5) Goodwill was allocated to the Upstream segment. (6) Provisional fair value measurements were made for assets acquired and liabilities assumed. Adjustments to those measurements may be made in subsequent periods, up to one year from the date of acquisition, as we continue to evaluate the information necessary to complete the analysis. 118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Debt Assumed in the Merger The following table presents long-term debt assumed at closing: (millions of dollars) Par Value Fair Value as of May 2, 2024 0.250 % Convertible Senior Notes due May 2025 (1) 450 1,327 1.125 % Senior Notes due January 2026 750 699 5.100 % Senior Notes due March 2026 1,100 1,096 7.200 % Senior Notes due January 2028 241 252 4.125 % Senior Notes due February 2028 138 130 1.900 % Senior Notes due August 2030 1,100 914 2.150 % Senior Notes due January 2031 1,000 832 (1) In June 2024, the Corporation redeemed in full all of the Convertible Senior Notes assumed from Pioneer for an amount consistent with the acquisition date fair value. Actual and Pro Forma Impact of Merger The following table presents revenues and earnings included in the Consolidated Statement of Income for Pioneer since the acquisition date (May 3, 2024) through December 31, 2024: (millions of dollars) Twelve Months Ended December 31, 2024 Sales and other operating revenues 17,008 Net income (loss) attributable to ExxonMobil 1,710 The following table presents unaudited pro forma information for the Corporation as if the merger with Pioneer had occurred at the beginning of January 1, 2023: Unaudited (millions of dollars) Twelve Months Ended December 31, 2024 2023 Sales and other operating revenues 347,406 358,014 Net income (loss) attributable to ExxonMobil 34,476 39,211 The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2023. In addition, the unaudited pro forma consolidated results reflect pro forma adjustments primarily related to conforming Pioneer's accounting policies to ExxonMobil, additional depreciation expense related to the fair value adjustment of the acquired property, plant and equipment, our capital structure, Pioneer's transaction-related costs, and applicable income tax impacts of the pro forma adjustments. Our transaction costs to effect the acquisition were immaterial. 119 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Denbury Inc. On November 2, 2023, the Corporation acquired Denbury, a developer of carbon capture, utilization, and storage solutions and enhanced oil recovery producing assets. The acquisition also included Gulf Coast and Rocky Mountain oil and natural gas operations. Total consideration was $ 5.1 billion, which included the issuance of 46 million shares of ExxonMobil common stock from treasury having a fair value of $ 4.8 billion on the acquisition date, and cash payments of $ 0.3 billion related to repayment of Denbury's credit facility and settlement of fractional shares. The transaction was accounted for as a business combination in accordance with ASC 805, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed: (billions of dollars) Denbury Current assets 0.4 Property, plant & equipment 6.4 Other assets 0.2 Total assets 7.0 Current liabilities 0.3 Long-term liabilities 1.6 Total liabilities 1.9 Net assets acquired 5.1 Inputs for the assumptions used in the income approach to value property, plant and equipment included estimates for pipeline tariff rates, pipeline throughput volumes, commodity prices, future oil and gas production profiles, operating expenses, and a risk-adjusted discount rate. The Denbury acquisition resulted in an immaterial amount of goodwill. Revenues and earnings arising from Denbury's operations are immaterial in 2023 for pro forma disclosure purposes. 120 SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited) The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, power operations, technical service agreements, gains and losses from derivative activity, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $1,395 million in 2024, $(519) million in 2023 and $4,802 million in 2022. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules. Results of Operations (millions of dollars) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total 2024 Consolidated Subsidiaries Sales to third parties 13,036 5,774 986 425 2,473 3,790 26,484 Transfers 13,745 13,140 43 5,764 10,825 817 44,334 Revenue 26,781 18,914 1,029 6,189 13,298 4,607 70,818 Production costs excluding taxes 6,869 4,745 406 1,723 1,163 610 15,516 Exploration expenses 43 485 46 213 31 8 826 Depreciation and depletion 11,114 3,343 94 1,436 1,390 852 18,229 Taxes other than income 2,163 115 31 479 1,987 370 5,145 Related income tax 1,502 2,025 202 605 6,562 805 11,701 Results of producing activities for consolidated subsidiaries 5,090 8,201 250 1,733 2,165 1,962 19,401 Equity Companies Sales to third parties 69 — 361 191 13,054 — 13,675 Transfers — — 15 — 142 — 157 Revenue 69 — 376 191 13,196 — 13,832 Production costs excluding taxes 58 — 422 50 659 — 1,189 Exploration expenses — — 2 — — — 2 Depreciation and depletion 239 — 36 35 781 — 1,091 Taxes other than income 6 — 10 — 4,469 — 4,485 Related income tax — — (48) 24 2,495 — 2,471 Results of producing activities for equity companies (234) — (46) 82 4,792 — 4,594 Total results of operations 4,856 8,201 204 1,815 6,957 1,962 23,995 121 Results of Operations (millions of dollars) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total 2023 Consolidated Subsidiaries Sales to third parties 5,098 4,027 1,345 298 2,490 4,588 17,846 Transfers 13,378 11,474 47 6,355 10,779 600 42,633 Revenue 18,476 15,501 1,392 6,653 13,269 5,188 60,479 Production costs excluding taxes 4,164 4,943 623 1,710 1,146 511 13,097 Exploration expenses 44 505 25 124 18 35 751 Depreciation and depletion 8,479 2,866 96 1,561 1,519 755 15,276 Taxes other than income 1,701 117 48 516 1,936 358 4,676 Related income tax 703 1,196 315 1,299 6,498 1,078 11,089 Results of producing activities for consolidated subsidiaries 3,385 5,874 285 1,443 2,152 2,451 15,590 Equity Companies Sales to third parties 182 — 1,211 214 14,653 — 16,260 Transfers 83 — 29 — 232 — 344 Revenue 265 — 1,240 214 14,885 — 16,604 Production costs excluding taxes 239 — 419 39 714 — 1,411 Exploration expenses — — — — — — — Depreciation and depletion 58 — 27 42 605 — 732 Taxes other than income 12 — 27 — 5,049 — 5,088 Related income tax — — 202 30 2,904 — 3,136 Results of producing activities for equity companies (44) — 565 103 5,613 — 6,237 Total results of operations 3,341 5,874 850 1,546 7,765 2,451 21,827 2022 Consolidated Subsidiaries Sales to third parties 8,801 4,401 2,388 463 2,710 6,222 24,985 Transfers 17,020 12,568 60 8,634 12,274 996 51,552 Revenue 25,821 16,969 2,448 9,097 14,984 7,218 76,537 Production costs excluding taxes 3,965 5,519 464 1,965 1,492 513 13,918 Exploration expenses 18 698 28 168 51 62 1,025 Depreciation and depletion 5,472 3,700 193 2,293 5,672 829 18,159 Taxes other than income 2,314 120 140 729 2,312 689 6,304 Related income tax 3,294 1,112 1,048 2,004 6,008 1,549 15,015 Results of producing activities for consolidated subsidiaries 10,758 5,820 575 1,938 (551) 3,576 22,116 Equity Companies Sales to third parties 820 — 2,791 10 20,750 — 24,371 Transfers 640 — 51 — 316 — 1,007 Revenue 1,460 — 2,842 10 21,066 — 25,378 Production costs excluding taxes 667 — 607 21 379 — 1,674 Exploration expenses — — 1 — — — 1 Depreciation and depletion 280 — 48 1 717 — 1,046 Taxes other than income 37 — 232 — 6,857 — 7,126 Related income tax — — 1,413 (2) 4,559 — 5,970 Results of producing activities for equity companies 476 — 541 (10) 8,554 — 9,561 Total results of operations 11,234 5,820 1,116 1,928 8,003 3,576 31,677 122 Oil and Gas Exploration and Production Costs The amounts shown for net capitalized costs of consolidated subsidiaries are $9,619 million less at year-end 2024 and $10,769 million less at year-end 2023 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 9 . This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations are included in the capitalized costs in accordance with Financial Accounting Standards Board rules. Capitalized Costs (millions of dollars) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total As of December 31, 2024 Consolidated Subsidiaries Property (acreage) costs – Proved 28,143 3,238 8 693 2,990 654 35,726 – Unproved 49,903 2,367 42 108 5 2,656 55,081 Total property costs 78,046 5,605 50 801 2,995 3,310 90,807 Producing assets 131,125 50,905 12,304 34,991 45,482 15,317 290,124 Incomplete construction 6,685 12,854 196 1,317 2,269 2,078 25,399 Total capitalized costs 215,856 69,364 12,550 37,109 50,746 20,705 406,330 Accumulated depreciation and depletion 74,303 27,479 11,953 32,837 32,822 10,534 189,928 Net capitalized costs for consolidated subsidiaries 141,553 41,885 597 4,272 17,924 10,171 216,402 Equity Companies Property (acreage) costs – Proved — — 3 309 — — 312 – Unproved — — — 3,111 — — 3,111 Total property costs — — 3 3,420 — — 3,423 Producing assets 1,360 — 5,222 402 19,215 — 26,199 Incomplete construction 2 — 15 453 5,091 — 5,561 Total capitalized costs 1,362 — 5,240 4,275 24,306 — 35,183 Accumulated depreciation and depletion 1,046 — 4,935 76 8,564 — 14,621 Net capitalized costs for equity companies 316 — 305 4,199 15,742 — 20,562 As of December 31, 2023 Consolidated Subsidiaries Property (acreage) costs – Proved 14,758 3,420 7 1,512 3,013 699 23,409 – Unproved 11,220 3,035 37 122 5 2,660 17,079 Total property costs 25,978 6,455 44 1,634 3,018 3,359 40,488 Producing assets 100,167 53,019 12,676 52,243 45,260 15,306 278,671 Incomplete construction 5,460 9,712 172 1,393 3,178 2,402 22,317 Total capitalized costs 131,605 69,186 12,892 55,270 51,456 21,067 341,476 Accumulated depreciation and depletion 72,548 27,224 12,289 48,751 32,764 10,424 204,000 Net capitalized costs for consolidated subsidiaries 59,057 41,962 603 6,519 18,692 10,643 137,476 Equity Companies Property (acreage) costs – Proved — — 4 309 — — 313 – Unproved — — — 3,111 — — 3,111 Total property costs — — 4 3,420 — — 3,424 Producing assets 1,332 — 5,493 288 10,153 — 17,266 Incomplete construction 1 — 11 550 13,083 — 13,645 Total capitalized costs 1,333 — 5,508 4,258 23,236 — 34,335 Accumulated depreciation and depletion 789 — 5,177 42 7,768 — 13,776 Net capitalized costs for equity companies 544 — 331 4,216 15,468 — 20,559 123 Oil and Gas Exploration and Production Costs (continued) The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2024 were $105,094 million, up $84,142 million from 2023, due primarily to the Pioneer acquisition and higher development costs. In 2023, costs were $20,952 million, up $6,439 million from 2022, due primarily to higher development costs and the Denbury acquisition. Total equity company costs incurred in 2024 were $1,134 million, down $376 million from 2023, due to lower development costs. Costs Incurred in Property Acquisitions, Exploration and Development Activities (millions of dollars) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total During 2024 Consolidated Subsidiaries Property acquisition costs – Proved 39,271 — — 1 — — 39,272 – Unproved 45,196 — 5 — — — 45,201 Exploration costs 55 838 63 268 30 8 1,262 Development costs 10,903 5,839 113 910 750 844 19,359 Total costs incurred for consolidated subsidiaries 95,425 6,677 181 1,179 780 852 105,094 Equity Companies Property acquisition costs – Proved — — — — — — — – Unproved — — — — — — — Exploration costs — — 2 — — — 2 Development costs 3 — 20 18 1,091 — 1,132 Total costs incurred for equity companies 3 — 22 18 1,091 — 1,134 During 2023 Consolidated Subsidiaries Property acquisition costs – Proved 2,456 — — 2 — — 2,458 – Unproved 171 — — 6 — — 177 Exploration costs 54 693 23 117 18 35 940 Development costs 8,978 5,914 55 562 822 1,046 17,377 Total costs incurred for consolidated subsidiaries 11,659 6,607 78 687 840 1,081 20,952 Equity Companies Property acquisition costs – Proved — — — — — — — – Unproved — — — — — — — Exploration costs — — — — — — — Development costs 10 — 5 7 1,488 — 1,510 Total costs incurred for equity companies 10 — 5 7 1,488 — 1,510 During 2022 Consolidated Subsidiaries Property acquisition costs – Proved 10 11 — 151 32 — 204 – Unproved 19 — — — — 7 26 Exploration costs 27 736 71 145 38 62 1,079 Development costs 5,821 4,759 161 533 1,490 440 13,204 Total costs incurred for consolidated subsidiaries 5,877 5,506 232 829 1,560 509 14,513 Equity Companies Property acquisition costs – Proved — — — — — — — – Unproved — — — — — — — Exploration costs — — 1 — — — 1 Development costs 95 — 13 22 1,638 — 1,768 Total costs incurred for equity companies 95 — 14 22 1,638 — 1,769 124 Oil and Gas Reserves The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2022, 2023, and 2024. The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. In accordance with the Securities and Exchange Commission’s (SEC) rules, the Corporation’s year-end reserves volumes, as well as the reserves change categories shown in the following tables, are required to be calculated on the basis of average prices during the 12-month period prior to the ending date of the period covered by this report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flows. Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment/facility capacity. Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Natural gas reserves exclude the gaseous equivalent of liquids expected to be removed from the natural gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids. In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies. Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves reported for these types of arrangements typically vary inversely with oil and natural gas price changes. As oil and natural gas prices increase, the cash flow and value received by the Company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total proved reserves (consolidated subsidiaries plus equity companies) at year-end 2024 that were associated with production sharing contract arrangements was 11 percent on an oil-equivalent basis (natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels). Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Crude oil, natural gas liquids, and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and natural gas reserves. The natural gas quantities differ from the quantities of natural gas delivered for sale by the producing function as reported in the Upstream Operational Results due to volumes consumed or flared and inventory changes. The changes between 2024 year-end proved reserves and 2023 year-end proved reserves include worldwide production of 1.6 billion oil-equivalent barrels (GOEB) and asset sales of 0.1 GOEB primarily in Nigeria. Additions to proved reserves include 2.3 GOEB related to the Pioneer acquisition, 1.9 GOEB from extensions and discoveries primarily in the United States and Guyana, and net revisions of 0.6 GOEB primarily attributed to the United Arab Emirates, United States, Canada, and Guyana. The changes between 2023 year-end proved reserves and 2022 year-end proved reserves include worldwide production of 1.4 billion GOEB, asset sales of 0.2 GOEB primarily in the United States, and downward revisions of 0.4 GOEB. Additions to proved reserves include 1.1 GOEB from extensions and discoveries primarily in the United States and Guyana and 0.2 GOEB related to the Denbury acquisition. The changes between 2022 year-end proved reserves and 2021 year-end proved reserves include worldwide production of 1.4 GOEB, asset sales of 0.4 GOEB primarily in the United States, and other downward revisions of 1.2 GOEB including the impact of the Russia expropriation (0.2 GOEB). Additions to proved reserves include 0.7 GOEB from purchases in Asia and 1.4 GOEB from extensions and discoveries primarily in the United States and Guyana. 125 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves Crude Oil Natural Gas Liquids Bitumen Synthetic Oil Total (millions of barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Worldwide Canada/ Other Americas Canada/ Other Americas Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2022 2,307 769 3 335 3,037 74 6,525 1,136 2,894 438 10,993 Revisions (1) (375) 52 3 38 (95) 2 (375) (85) (422) (62) (944) Improved recovery — — — — — — — — — — — Purchases 1 — — — — — 1 — — — 1 Sales (3) (12) — (17) — — (32) (20) — — (52) Extensions/discoveries 465 208 — — — — 673 235 67 — 975 Production (191) (72) (1) (85) (148) (10) (507) (90) (119) (23) (739) December 31, 2022 2,204 945 5 271 2,794 66 6,285 1,176 2,420 353 10,234 Attributable to noncontrolling interests 14 554 107 Proportional interest in proved reserves of equity companies January 1, 2022 155 — 10 5 741 — 911 270 — — 1,181 Revisions (21) — (7) — (17) — (45) (10) — — (55) Improved recovery — — — — — — — — — — — Purchases — — — — 110 — 110 117 — — 227 Sales — — — — — — — — — — — Extensions/discoveries — — — — — — — — — — — Production (15) — (1) — (78) — (94) (22) — — (116) December 31, 2022 119 — 2 5 756 — 882 355 — — 1,237 Total liquids proved reserves at December 31, 2022 2,323 945 7 276 3,550 66 7,167 1,531 2,420 353 11,471 (1) Includes (118) million barrels in Russia which were expropriated. See Note 2 . Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2023 2,204 945 5 271 2,794 66 6,285 1,176 2,420 353 10,234 Revisions (398) 32 — 31 30 3 (302) (110) 123 26 (263) Improved recovery — — — — — — — — — — — Purchases 156 — — — — — 156 2 — — 158 Sales (12) — — — (4) — (16) (5) — — (21) Extensions/discoveries 355 105 — — — — 460 272 — — 732 Production (203) (88) (1) (78) (153) (8) (531) (99) (129) (25) (784) December 31, 2023 2,102 994 4 224 2,667 61 6,052 1,236 2,414 354 10,056 Attributable to noncontrolling interests 1 551 108 Proportional interest in proved reserves of equity companies January 1, 2023 119 — 2 5 756 — 882 355 — — 1,237 Revisions — — 1 — 103 — 104 1 — — 105 Improved recovery — — — — — — — — — — — Purchases — — — — — — — — — — — Sales (108) — — — — — (108) (1) — — (109) Extensions/discoveries — — — — — — — — — — — Production (4) — — — (79) — (83) (22) — — (105) December 31, 2023 7 — 3 5 780 — 795 333 — — 1,128 Total liquids proved reserves at December 31, 2023 2,109 994 7 229 3,447 61 6,847 1,569 2,414 354 11,184 126 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) Crude Oil Natural Gas Liquids Bitumen Synthetic Oil Total (millions of barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Worldwide Canada/ Other Americas Canada/ Other Americas Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2024 2,102 994 4 224 2,667 61 6,052 1,236 2,414 354 10,056 Revisions (176) 116 — 62 603 1 606 (128) 152 (35) 595 Improved recovery — — — — — — — — — — — Purchases 877 — — — — — 877 730 — — 1,607 Sales (18) (4) — (45) (7) — (74) (15) — — (89) Extensions/discoveries 804 138 — 25 — — 967 489 — — 1,456 Production (316) (126) (1) (75) (154) (7) (679) (148) (137) (23) (987) December 31, 2024 3,273 1,118 3 191 3,109 55 7,749 2,164 2,429 296 12,638 Attributable to noncontrolling interests 552 90 Proportional interest in proved reserves of equity companies January 1, 2024 7 — 3 5 780 — 795 333 — — 1,128 Revisions — — — 2 19 — 21 3 — — 24 Improved recovery — — — — — — — — — — — Purchases — — — — — — — — — — — Sales — — — — — — — — — — — Extensions/discoveries — — — — — — — — — — — Production (1) — (1) — (75) — (77) (22) — — (99) December 31, 2024 6 — 2 7 724 — 739 314 — — 1,053 Total liquids proved reserves at December 31, 2024 3,279 1,118 5 198 3,833 55 8,488 2,478 2,429 296 13,691 127 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) Crude Oil and Natural Gas Liquids Bitumen Synthetic Oil Total (millions of barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Canada/ Other Americas Canada/ Other Americas As of December 31, 2022 Proved developed reserves Consolidated subsidiaries 1,688 378 5 259 2,067 50 4,447 2,288 248 6,983 Equity companies 126 — 2 5 360 — 493 — — 493 Proved undeveloped reserves Consolidated subsidiaries 1,568 568 — 35 813 30 3,014 132 105 3,251 Equity companies — — — — 744 — 744 — — 744 Total liquids proved reserves at December 31, 2022 3,382 946 7 299 3,984 80 8,698 2,420 353 11,471 As of December 31, 2023 Proved developed reserves Consolidated subsidiaries 1,735 433 4 217 1,996 45 4,430 2,307 242 6,979 Equity companies 11 — 3 5 438 — 457 — — 457 Proved undeveloped reserves Consolidated subsidiaries 1,498 561 — 20 751 28 2,858 107 112 3,077 Equity companies — — — — 671 — 671 — — 671 Total liquids proved reserves at December 31, 2023 3,244 994 7 242 3,856 73 8,416 2,414 354 11,184 As of December 31, 2024 Proved developed reserves Consolidated subsidiaries 3,053 473 3 153 1,969 40 5,691 2,308 190 8,189 Equity companies 9 — 2 7 569 — 587 — — 587 Proved undeveloped reserves Consolidated subsidiaries 2,308 646 — 38 1,208 22 4,222 121 106 4,449 Equity companies — — — — 466 — 466 — — 466 Total liquids proved reserves at December 31, 2024 5,370 1,119 5 198 4,212 62 10,966 (1) 2,429 296 13,691 (1) See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves, see Item 2 in ExxonMobil’s 2024 Form 10-K. 128 Natural Gas and Oil-Equivalent Proved Reserves Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) (millions of oil-equivalent barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2022 14,988 919 383 317 3,693 6,363 26,663 15,436 Revisions (2) (990) (38) 149 49 (307) 187 (950) (1,102) Improved recovery — — — — — — — — Purchases 2 — — — — — 2 1 Sales (1,551) (272) — (1) — — (1,824) (356) Extensions/discoveries 2,232 175 — — — — 2,407 1,376 Production (1,036) (76) (119) (53) (325) (542) (2,151) (1,097) December 31, 2022 13,645 708 413 312 3,061 6,008 24,147 14,258 Attributable to noncontrolling interests 77 Proportional interest in proved reserves of equity companies January 1, 2022 140 — 408 806 10,158 — 11,512 3,100 Revisions (3) — 104 (132) 29 — (2) (55) Improved recovery — — — — — — — — Purchases — — — — 3,101 — 3,101 744 Sales — — — — — — — — Extensions/discoveries — — — — — — — — Production (10) — (132) (11) (979) — (1,132) (305) December 31, 2022 127 — 380 663 12,309 — 13,479 3,484 Total proved reserves at December 31, 2022 13,772 708 793 975 15,370 6,008 37,626 17,742 Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2023 13,645 708 413 312 3,061 6,008 24,147 14,258 Revisions (1,945) (201) (3) (49) 121 339 (1,738) (553) Improved recovery — — — — — — — — Purchases 7 — — — — — 7 159 Sales (417) (1) — — (9) — (427) (92) Extensions/discoveries 1,930 67 — — — — 1,997 1,065 Production (957) (53) (103) (43) (379) (489) (2,024) (1,121) December 31, 2023 12,263 520 307 220 2,794 5,858 21,962 13,716 Attributable to noncontrolling interests 26 Proportional interest in proved reserves of equity companies January 1, 2023 127 — 380 663 12,309 — 13,479 3,484 Revisions (27) — 18 157 (32) — 116 124 Improved recovery — — — — — — — — Purchases — — — — — — — — Sales (35) — — — — — (35) (115) Extensions/discoveries — — — — — — — — Production (8) — (54) (40) (956) — (1,058) (281) December 31, 2023 57 — 344 780 11,321 — 12,502 3,212 Total proved reserves at December 31, 2023 12,320 520 651 1,000 14,115 5,858 34,464 16,928 (1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. (2) Includes (199) billion cubic feet of natural gas and (152) million total oil-equivalent barrels in Russia which were expropriated. See Note 2 . 129 Natural Gas and Oil-Equivalent Proved Reserves (continued) Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) (millions of oil-equivalent barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2024 12,263 520 307 220 2,794 5,858 21,962 13,716 Revisions (911) 22 198 24 124 97 (446) 521 Improved recovery — — — — — — — — Purchases 4,044 — — — — — 4,044 2,281 Sales (83) (10) — (105) (5) — (203) (123) Extensions/discoveries 2,683 68 — 2 — 1 2,754 1,915 Production (1,153) (59) (99) (46) (373) (477) (2,207) (1,355) December 31, 2024 16,843 541 406 95 2,540 5,479 25,904 16,955 Attributable to noncontrolling interests 20 Proportional interest in proved reserves of equity companies January 1, 2024 57 — 344 780 11,321 — 12,502 3,212 Revisions (3) — 9 80 49 — 135 46 Improved recovery — — — — — — — — Purchases — — — — — — — — Sales — — — — — — — — Extensions/discoveries — — — — — — — — Production (7) — (37) (44) (904) — (992) (264) December 31, 2024 47 — 316 816 10,466 — 11,645 2,994 Total proved reserves at December 31, 2024 16,890 541 722 911 13,006 5,479 37,549 19,949 (1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. 130 Natural Gas and Oil-Equivalent Proved Reserves (continued) Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) (millions of oil-equivalent barrels) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total As of December 31, 2022 Proved developed reserves Consolidated subsidiaries 9,577 371 408 307 2,037 3,162 15,862 9,627 Equity companies 127 — 326 663 5,020 — 6,136 1,516 Proved undeveloped reserves Consolidated subsidiaries 4,068 337 5 5 1,024 2,846 8,285 4,631 Equity companies — — 54 — 7,289 — 7,343 1,968 Total proved reserves at December 31, 2022 13,772 708 793 975 15,370 6,008 37,626 17,742 As of December 31, 2023 Proved developed reserves Consolidated subsidiaries 8,138 329 307 220 1,935 3,163 14,092 9,327 Equity companies 57 — 290 780 4,223 — 5,350 1,349 Proved undeveloped reserves Consolidated subsidiaries 4,125 191 — — 859 2,695 7,870 4,389 Equity companies — — 54 — 7,098 — 7,152 1,863 Total proved reserves at December 31, 2023 12,320 520 651 1,000 14,115 5,858 34,464 16,928 As of December 31, 2024 Proved developed reserves Consolidated subsidiaries 11,671 296 406 93 1,900 3,204 17,570 11,118 Equity companies 47 — 262 816 4,242 — 5,367 1,481 Proved undeveloped reserves Consolidated subsidiaries 5,172 245 — 2 640 2,275 8,334 5,838 Equity companies — — 54 — 6,224 — 6,278 1,512 Total proved reserves at December 31, 2024 16,890 541 722 911 13,006 5,479 37,549 19,949 (1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. 131 Standardized Measure of Discounted Future Cash Flows As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates, and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment, and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. Standardized Measure of Discounted Future Cash Flows (millions of dollars) United States Canada/Other Americas (1) Europe Africa Asia Australia/ Oceania Total As of December 31, 2022 Consolidated Subsidiaries Future cash inflows from sales of oil and gas 316,486 284,643 11,806 30,040 271,732 114,959 1,029,666 Future production costs 78,939 113,264 2,627 7,489 63,705 21,972 287,996 Future development costs 31,960 34,968 2,016 6,143 9,241 7,089 91,417 Future income tax expenses 45,278 31,603 3,164 8,300 156,595 24,955 269,895 Future net cash flows 160,309 104,808 3,999 8,108 42,191 60,943 380,358 Effect of discounting net cash flows at 10% 83,711 49,861 187 322 21,772 34,896 190,749 Discounted future net cash flows 76,598 54,947 3,812 7,786 20,419 26,047 189,609 Equity Companies Future cash inflows from sales of oil and gas 12,312 — 13,706 7,194 261,409 — 294,621 Future production costs 5,379 — 1,981 266 96,788 — 104,414 Future development costs 1,773 — 895 60 7,275 — 10,003 Future income tax expenses — — 5,262 1,965 51,838 — 59,065 Future net cash flows 5,160 — 5,568 4,903 105,508 — 121,139 Effect of discounting net cash flows at 10% 2,236 — 2,234 2,694 44,728 — 51,892 Discounted future net cash flows 2,924 — 3,334 2,209 60,780 — 69,247 Total consolidated and equity interests in standardized measure of discounted future net cash flows 79,522 54,947 7,146 9,995 81,199 26,047 258,856 (1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $6,596 million in 2022. 132 Standardized Measure of Discounted Future Cash Flows (continued) (millions of dollars) United States Canada/Other Americas (1) Europe Africa Asia Australia/ Oceania Total As of December 31, 2023 Consolidated Subsidiaries Future cash inflows from sales of oil and gas 213,623 227,365 3,918 19,282 221,822 63,204 749,214 Future production costs 68,753 113,875 1,611 5,025 52,672 13,971 255,907 Future development costs 37,784 38,436 1,881 4,466 11,926 6,393 100,886 Future income tax expenses 14,270 15,973 509 4,337 121,751 12,119 168,959 Future net cash flows 92,816 59,081 (83) 5,454 35,473 30,721 223,462 Effect of discounting net cash flows at 10% 49,199 23,471 (762) 402 18,537 16,215 107,062 Discounted future net cash flows 43,617 35,610 679 5,052 16,936 14,506 116,400 Equity Companies Future cash inflows from sales of oil and gas 818 — 5,101 4,393 158,643 — 168,955 Future production costs 503 — 982 233 73,496 — 75,214 Future development costs 75 — 697 100 5,452 — 6,324 Future income tax expenses — — 1,539 1,120 24,374 — 27,033 Future net cash flows 240 — 1,883 2,940 55,321 — 60,384 Effect of discounting net cash flows at 10% 76 — 672 1,635 20,135 — 22,518 Discounted future net cash flows 164 — 1,211 1,305 35,186 — 37,866 Total consolidated and equity interests in standardized measure of discounted future net cash flows 43,781 35,610 1,890 6,357 52,122 14,506 154,266 As of December 31, 2024 Consolidated Subsidiaries Future cash inflows from sales of oil and gas 312,279 236,954 4,339 15,493 250,850 54,247 874,162 Future production costs 109,915 96,932 1,583 3,167 60,404 12,599 284,600 Future development costs 48,781 37,253 1,921 3,675 17,608 6,083 115,321 Future income tax expenses 21,728 21,738 644 2,801 129,925 9,846 186,682 Future net cash flows 131,855 81,031 191 5,850 42,913 25,719 287,559 Effect of discounting net cash flows at 10% 64,731 34,232 (387) 1,419 23,172 12,898 136,065 Discounted future net cash flows 67,124 46,799 578 4,431 19,741 12,821 151,494 Equity Companies Future cash inflows from sales of oil and gas 614 — 3,557 5,685 138,978 — 148,834 Future production costs 379 — 766 534 66,969 — 68,648 Future development costs 69 — 709 55 4,243 — 5,076 Future income tax expenses — — 1,106 1,431 19,566 — 22,103 Future net cash flows 166 — 976 3,665 48,200 — 53,007 Effect of discounting net cash flows at 10% 42 — 298 2,099 16,397 — 18,837 Discounted future net cash flows 124 — 677 1,566 31,803 — 34,170 Total consolidated and equity interests in standardized measure of discounted future net cash flows 67,248 46,799 1,255 5,997 51,544 12,821 185,664 (1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $3,055 million in 2023 and $4,466 million in 2024. 133 Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Consolidated and Equity Interests (millions of dollars) 2022 Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests Discounted future net cash flows as of December 31, 2021 115,880 37,939 153,819 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 18,592 3,008 21,600 Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (57,344) (17,037) (74,381) Development costs incurred during the year 11,834 1,849 13,683 Net change in prices, lifting and development costs 139,844 51,094 190,938 Revisions of previous reserves estimates (1,985) 2,140 155 Accretion of discount 14,655 4,938 19,593 Net change in income taxes (51,867) (14,684) (66,551) Total change in the standardized measure during the year 73,729 31,308 105,037 Discounted future net cash flows as of December 31, 2022 189,609 69,247 258,856 Consolidated and Equity Interests (millions of dollars) 2023 Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests Discounted future net cash flows as of December 31, 2022 189,609 69,247 258,856 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 5,658 (1,701) 3,957 Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (43,836) (10,218) (54,054) Development costs incurred during the year 15,343 1,502 16,845 Net change in prices, lifting and development costs (120,924) (51,923) (172,847) Revisions of previous reserves estimates 4,953 5,096 10,049 Accretion of discount 23,006 8,962 31,968 Net change in income taxes 42,591 16,901 59,492 Total change in the standardized measure during the year (73,209) (31,381) (104,590) Discounted future net cash flows as of December 31, 2023 116,400 37,866 154,266 Consolidated and Equity Interests (millions of dollars) 2024 Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests Discounted future net cash flows as of December 31, 2023 116,400 37,866 154,266 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 42,405 — 42,405 Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (51,236) (8,268) (59,504) Development costs incurred during the year 18,924 1,135 20,059 Net change in prices, lifting and development costs (4,549) (5,811) (10,360) Revisions of previous reserves estimates 20,779 1,690 22,469 Accretion of discount 15,232 4,853 20,085 Net change in income taxes (6,461) 2,705 (3,756) Total change in the standardized measure during the year 35,094 (3,696) 31,398 Discounted future net cash flows as of December 31, 2024 151,494 34,170 185,664 134 INDEX TO EXHIBITS Exhibit Description 3(i) Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015). 3(ii) By-Laws, as amended effective October 25, 2022 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of October 31, 2022). 4(vi) Description of ExxonMobil Capital Stock (incorporated by reference to Exhibit 4(vi) to the Registrant's Annual Report on Form 10-K for 2019). 10(iii)(a.1) 2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2017).* 10(iii)(a.2) Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2016).* 10(iii)(a.3) Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.* 10(iii)(b.1) Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual Report on Form 10-K for 2023).* 10(iii)(b.2) Earnings Bonus Unit instrument (incorporated by reference to Exhibit 10(iii)(b.2) to the Registrant's Annual Report on Form 10-K for 2019).* 10(iii)(b.3) Amendment of 2018 and 2019 Earnings Bonus Unit instruments, effective November 23, 2021 (incorporated by reference to Exhibit 99.1 to the Registrant's Report on Form 8-K of November 30, 2021).* 10(iii )(b.4) Pioneer Natural Resources Company Second Amended and Restated 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10(iii)(b.4) to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2024).* 10(iii)(c.1) ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant's Annual Report on Form 10-K for 2022).* 10(iii)(c.2) ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant's Annual Report on Form 10-K for 2022).* 10(iii)(c.3) ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual Report on Form 10-K for 2023).* 10(iii)(d) ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2016).* 10(iii)(f.1) 2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2018).* 10(iii)(f.2) Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Annual Report on Form 10-K for 2016).* 10(iii)(f.3) Form of restricted stock grant letter for non-employee directors.* 10(iii)(f.4) Standing resolution for non-employee director cash fees dated March 1, 2020, as amended effective July 29, 2024 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Report on Form 10-Q for the quarter ended September 30, 2024).* 10(iii)(g) Aircraft Time Share Agreement dated as of August 29, 2023, between Exxon Mobil Corporation and Darren W. Woods (incorporated by reference to Exhibit 10(iii)(g) to the Registrant’s Report on Form 10-Q for the quarter ended October 31, 2023).* 14 Code of Ethics and Business Conduct. 19 Insider Trading Policy. 21 Subsidiaries of the registrant. 23 Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. 31.1 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer. 31.2 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Financial Officer. 31.3 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer. 32.1 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer. 32.2 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Financial Officer. 32.3 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer. 97 Policy Relating to Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97 to the Registrant’s Annual Report on Form 10-K for 2023). 101 Interactive data files (formatted as Inline XBRL). 104 Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101). * Management contract or compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K. The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request. 135 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. EXXON MOBIL CORPORATION By: /s/ DARREN W. WOODS Dated February 19, 2025 Darren W. Woods, Chairman of the Board POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Matthew R. Rasmussen, Brian J. Conjelko, and Antony E. Peters and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 19, 2025. Principal Executive Officer Directors /s/ DARREN W. WOODS /s/ MICHAEL J. ANGELAKIS /s/ STEVEN A. KANDARIAN Darren W. Woods, Chairman of the Board Michael J. Angelakis Steven A. Kandarian /s/ ANGELA F. BRALY /s/ ALEXANDER A. KARSNER Principal Financial Officer Angela F. Braly Alexander A. Karsner /s/ KATHRYN A. MIKELLS /s/ MARIA S. DREYFUS /s/ LAWRENCE W. KELLNER Kathryn A. Mikells, Senior Vice President and Chief Financial Officer Maria S. Dreyfus Lawrence W. Kellner /s/ JOHN D. HARRIS II /s/ DINA POWELL MCCORMICK Principal Accounting Officer John D. Harris II Dina Powell McCormick /s/ LEN M. FOX /s/ KAISA H. HIETALA /s/ JEFFREY W. UBBEN Len M. Fox, Vice President, Controller and Tax Kaisa H. Hietala Jeffrey W. Ubben /s/ JOSEPH L. HOOLEY Joseph L. Hooley 136