Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
Overview
Business Environment
Business Results
Liquidity and Capital Resources
Taxes
Environmental Matters
Market Risks
Critical Accounting Estimates
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Statement of Income
Statement of Comprehensive Income
Balance Sheet
Statement of Cash Flows
Statement of Changes in Equity
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies
2. Earnings Per Share
3. Disclosures about Segments and Related Information
4. Pension and Other Postretirement Benefits
5. Other Comprehensive Income Information
6. Financial Instruments and Derivatives
7. Litigation and Other Contingencies
8. Equity Company Information
9. Property, Plant , and Equipment and Asset Retirement Obligations
10. Additional Working Capital Information
11. Investments, Advances , and Long-Term Receivables
12. Long-Term Debt
13. Leases
14. Miscellaneous Financial Information
15. Income and Other Taxes
16. Accounting for Suspended Exploratory Well Costs
17. Cash Flow Information
18. Incentive Program
19. Divestment Activities
20. Mergers and Acquisitions
Supplemental Information on Oil and Gas Exploration and Production Activities
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BUSINESS PROFILE
Earnings (Loss) After
Income Taxes
Average Capital
Employed (Non-GAAP)
Return on
Average Capital
Employed (Non-GAAP)
Cash Capital
Expenditures
( Non-GAAP)
Financial
(millions of dollars)
(millions of dollars)
(percent)
(millions of dollars)
Upstream
United States
Non-U.S.
Total
Energy Products
United States
Non-U.S.
Total
Chemical Products
United States
Non-U.S.
Total
Specialty Products
United States
Non-U.S.
Total
Corporate and Financing
Corporate total
See Frequently Used Terms for a definition and calculation of capital employed, return on average capital employed, and cash capital expenditures.
Due to rounding, numbers presented may not add up precisely to the totals indicated.
Operating
Net liquids production
(thousands of barrels daily)
Refinery throughput
(thousands of barrels daily)
United States
United States
Non-U.S.
Non-U.S.
Total
Total
Natural gas production available for sale
(millions of cubic feet daily)
Energy Products sales (2)
(thousands of barrels daily)
United States
United States
Non-U.S.
Non-U.S.
Total
Total
Oil-equivalent production (1)
(thousands of oil-equivalent barrels daily)
Chemical Products sales (2)
(thousands of metric tons)
United States
Non-U.S.
Total
Specialty Products sales (2)
(thousands of metric tons)
United States
Non-U.S.
Total
(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.
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FINANCIAL INFORMATION
(millions of dollars, except where stated otherwise)
Sales and other operating revenue
Net income (loss) attributable to ExxonMobil
Earnings (loss) per common share (dollars)
Earnings (loss) per common share – assuming dilution (dollars)
Earnings (loss) to average ExxonMobil share of equity (percent)
Working capital
Ratio of current assets to current liabilities (times)
Additions to property, plant, and equipment (1)
Property, plant, and equipment, less allowances
Total assets
Exploration expenses, including dry holes
Research and development costs
Long-term debt
Total debt
Debt to capital (percent)
Net debt to capital (percent) (2)
ExxonMobil share of equity at year-end
ExxonMobil share of equity per common share (dollars)
Weighted-average number of common shares outstanding (millions)
Number of regular employees at year-end (thousands) (3)
(1) Includes non-cash additions. See Note 20 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.
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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, the Company believes it is useful for investors to consider proceeds associated with the sales of subsidiaries; property, plant, and equipment; and sales and returns of investments 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)
Net cash provided by operating activities
Proceeds associated with sales of subsidiaries, property, plant, and equipment, and sales and returns of investments
Cash flow from operations and asset sales (Non-GAAP)
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)
Business uses: asset and liability perspective
Total assets
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable
Total long-term liabilities excluding long-term debt
Noncontrolling interests share of assets and liabilities
Add ExxonMobil share of debt-financed equity company net assets
Total capital employed (Non-GAAP)
Total corporate sources: debt and equity perspective
Notes and loans payable
Long-term debt
ExxonMobil share of equity
Less noncontrolling interests share of total debt
Add ExxonMobil share of equity company debt
Total capital employed (Non-GAAP)
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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)
Net income (loss) attributable to ExxonMobil
Financing costs (after-tax)
Gross third-party debt
ExxonMobil share of equity companies
All other financing costs – net
Total financing costs
Earnings (loss) excluding financing costs (Non-GAAP)
Average capital employed (Non-GAAP)
Return on average capital employed – Corporate total (Non-GAAP)
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, 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.
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).
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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 $15.1 billion, which included an additional $3.0 billion in 2025. The total change between periods in expenses below will reflect both Structural Cost Savings and other changes in spend, including market drivers, 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 developments, and early-stage projects. Structural Cost Savings from new operations, mergers and acquisitions, and new business venture developments are included in the cumulative Structural Cost Savings. 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)
Components of Operating Costs
From ExxonMobil’s Consolidated Statement of Income
(U.S. GAAP)
Production and manufacturing expenses
Selling, general and administrative expenses
Depreciation and depletion (includes impairments)
Exploration expenses, including dry holes
Non-service pension and postretirement benefit expense
Subtotal
ExxonMobil’s share of equity company expenses (Non-GAAP)
Total Adjusted Operating Costs (Non-GAAP)
Total Adjusted Operating Costs (Non-GAAP)
Less:
Depreciation and depletion (includes impairments)
Non-service pension and postretirement benefit expense
Other adjustments (includes equity company depreciation
and depletion)
Total Cash Operating Expenses (Cash Opex) (Non-GAAP)
Energy and production taxes (Non-GAAP)
Market
Activity/ Other
Structural Cost Savings
Total Cash Operating Expenses (Cash Opex) excluding Energy and Production Taxes (Non-GAAP)
Due to rounding, numbers presented may not add up precisely to the totals indicated.
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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 periods or several segments. Earnings/(loss) excluding Identified Items does include non-operational earnings events or impacts that are generally below the $250 million threshold utilized for identified items. 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
(millions of dollars)
Non-U.S.
Total
Non-U.S.
Total
Non-U.S.
Total
Earnings (loss) (U.S. GAAP)
Impairments
Gain/(loss) on sale of assets
Tax-related items
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
Energy Products
(millions of dollars)
Non-U.S.
Total
Non-U.S.
Total
Non-U.S.
Total
Earnings (loss) (U.S. GAAP)
Impairments
Gain/(loss) on sale of assets
Tax-related items
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
Chemical Products
(millions of dollars)
Non-U.S.
Total
Non-U.S.
Total
Non-U.S.
Total
Earnings (loss) (U.S. GAAP)
Impairments
Tax-related items
Other
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
Specialty Products
(millions of dollars)
Non-U.S.
Total
Non-U.S.
Total
Non-U.S.
Total
Earnings (loss) (U.S. GAAP)
Impairments
Tax-related items
Other
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
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FREQUENTLY USED TERMS
Corporate and Financing
(millions of dollars)
Earnings (loss) (U.S. GAAP)
Impairments
Gain/(loss) on sale of assets
Tax-related items
Restructuring charges
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
Corporate Total
(millions of dollars)
Net income (loss) attributable to ExxonMobil (U.S. GAAP)
Impairments
Gain/(loss) on sale of assets
Tax-related items
Restructuring charges
Other
Identified Items
Earnings (loss) excluding Identified Items (Non-GAAP)
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.
Cash Capital Expenditures (Non-GAAP)
Cash capital expenditures (Cash Capex) are 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 Company believes it is a useful measure for investors to understand the cash impact of investments in the business, which is in line with industry practice.
(millions of dollars)
Additions to property, plant, and equipment
Additional investments and advances
Other investing activities including collection of advances
Inflows from noncontrolling interests for major projects
Total Cash Capex (Non-GAAP)
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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; future earnings power; potential addressable markets; 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, hydrogen and ammonia, lower-emission fuels, direct air capture, Proxxima TM resin systems, carbon materials, low-carbon data centers, lithium, and other future plans to reduce emissions and emissions 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; 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 integrated Upstream Permian Basin unconventional operated assets by 2035, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, to reach near-zero methane emissions from operated assets and other methane initiatives, and 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 resin systems, produce carbon materials, produce lithium, and use plastic waste as feedstock for advanced recycling; future debt levels and credit ratings; business and project plans, timing, costs, capacities and profitability; resource recoveries and production rates; and planned Denbury and Pioneer integrated benefits, could differ materially due to a number of factors.
These include global or regional changes or imbalances in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and other market factors; economic conditions and seasonal fluctuations that impact prices, differentials, and volume/mix 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 voluntary and mandatory standards or extraterritorial laws and regulations imposed by various jurisdictions related to sustainability and greenhouse gas reporting; timely granting of governmental permits, licenses, and certifications; uncertain impacts of deregulation on the legal and regulatory environment; changes in interest and exchange rates; variable impacts of trading activities on our margins and results each quarter; actions of co-venturers or partners, competitors, and commercial counterparties, including suppliers and customers; government actions in pursuit of national energy and security policies and priorities affecting our business; 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 and optimization, including variability and timing factors applicable to unconventional resources, the success of new unconventional technologies, and the ability of new technologies to improve recovery relative to competitors; the level, outcome, and timing of exploration and development projects and decisions to invest in future reserves and resources; timely completion of construction projects and commencement of start-up operations, including reliance on third-party suppliers and service providers; final management approval of future projects and any changes in the scope, terms, costs, or assumptions of such projects as approved; the actions of governments, non-governmental organizations, or other actors against our core business activities and acquisitions, divestitures or financing opportunities; war, civil unrest, armed hostilities, attacks against the Company or industry, and other geopolitical or security disturbances, including disruption of land or sea transportation routes or distribution or shipping channels; decoupling of economies, disruption, realignment, or breaking of current or historical trade or military alliances or global trade or supply chain networks; escalating geopolitical volatility, including regime changes; expropriations, seizures, or capacity, insurance, shipping, import or export limitations imposed directly or indirectly 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 disruptions or 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.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 ExxonMobil’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 Corporate 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 and ammonia, lower-emission fuels, Proxxima TM resin systems, carbon materials, low-carbon data centers, 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, 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 the 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.
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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; 2025 World Energy Outlook (WEO)), which reflects a sector-by-sector assessment of current policy in place and those announced by governments; IEA Announced Pledges Scenario (APS; 2024 WEO), which reflects aspirational government targets met on time and in full; and IEA Net Zero Emissions by 2050 Scenario (NZE; 2025 WEO), which the IEA describes as highly ambitious and 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 2025 Global Outlook
By 2050, the world’s population is projected to be around 9.7 billion people, or nearly 2 billion more than in 2024. 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 2024. 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 over 10 percent from 2024 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 70 percent from 2024 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 2024, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2024 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 nearly 400 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.
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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 nearly 25 percent from 2024 to 2050. Transportation energy demand is expected to account for over 50 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to have peaked this decade, and then decline to levels seen in the early-2010s 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 about 60 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, et cetera 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 60 percent between 2024 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 nearly 115 million oil-equivalent barrels per day, an increase of about 10 percent from 2024. The non-OECD share of global liquid fuels demand is expected to increase to about 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 nearly 20 percent from 2024 to 2050, with approximately 70 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, over 40 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 75 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in the Asia Pacific region.
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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 2025 Global Outlook
Source: ExxonMobil 2025 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 nearly 350 percent from 2024 to 2050, when they are projected to be greater than 10 percent of the world energy mix.
Decarbonization of industrial activities will require a suite of lower-carbon technologies supported by stable 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.
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Significant oil and natural gas investment needed to meet projected global demand
Projected global oil supply and demand
Projected global natural gas supply and demand
Million barrels per day
Billion cubic feet per day
Excludes biofuels; IEA STEPS and IEA NZE Source: IEA WEO 2025; IEA APS Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2025 Global Outlook; IPCC Likely Below 2°C Average 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 Grown Rate (CAGR)
Excludes flaring; IEA STEPS and IEA NZE Source: IEA WEO 2025; IEA APS Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2025 Global Outlook; IPCC Likely Below 2°C Average 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 65 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 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.
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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. In 2022, we announced our ambition to achieve net-zero Scope 1 and 2 greenhouse gas emissions in our operated assets by 2050, with advancements in technology and clear, consistent, stable, and effective government policies. Society's progress continues to lag in these areas. Without supportive policies and the innovations they drive, net zero 2050 will remain out of reach — for society and ExxonMobil. 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. 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 pace of an energy transition. Our plans include reaching net-zero Scope 1 and 2 emissions in our integrated Permian Basin operated assets by 2035, including Pioneer assets acquired in 2024. By 2030, we plan to reduce emissions in our combined Permian operations by more than the equivalent of achieving net-zero Scope 1 and 2 emissions in our operated heritage ExxonMobil assets.
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.
As of year-end 2025, we are exceeding our 2030 plans across the portfolio, having already achieved our plans for reducing Corporate greenhouse gas and flaring intensity. We expect to reach the plan for methane intensity reductions later this year.
Our emission-reduction plans and 2050 net-zero ambition cover Scope 1 and 2 emissions from assets we operate.
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 and ammonia, lower-emission fuels, Proxxima TM resin systems, carbon materials, and low-carbon data centers, 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 grow a carbon capture and storage business that will enable industrial customers to reduce their emissions. 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.
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Recent Business Environment
During 2025, the price of crude oil remained near the middle of the pre-COVID 10-year range (2010-2019) as global markets remained broadly balanced. Record crude demand was met by increasing industry supply, resulting in modestly lower prices. Natural gas prices rose to the top end of the 10-year range due to robust demand. Industry refining margins improved in 2025, supported by record full-year demand and an increase in supply disruptions driving higher margins. Despite record demand, global oversupply resulted in Chemical margins remaining at bottom-of-cycle.
During 2025, the U.S. announced a variety of trade-related actions, including the imposition of tariffs on imports from several countries. In response, many countries announced their own retaliatory tariffs. Despite the current uncertainty as to what effects these actions will ultimately have on the Corporation, our suppliers and our customers, as well as on the overall macroeconomic environment, we do not anticipate any material near-term financial impacts.
The Corporation closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. Strategic changes implemented over the past several years enabled the Corporation to capture $15.1 billion of structural cost savings (1) versus 2019, including $3 billion of savings during 2025, through increased operational efficiencies, workforce reductions, divestment-related reductions, and other cost-saving measures. The Company sees additional opportunities in areas such as centralization of activities, system implementations, continued improvement of maintenance and turnarounds, and simplified business processes. These savings are key drivers to reduce our structural costs by $20 billion between 2019 and 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 2025 were approximately $1.1 billion, and its share of combined oil and gas production was approximately 320 thousand oil-equivalent barrels per day.
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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. In 2025, Upstream production averaged 4.7 million oil-equivalent barrels per day (Moebd), our highest production in over 40 years. 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 Permian, Guyana, 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 typically 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 2025, crude prices remained within the 10-year historical range (2010-2019), while robust demand helped to move natural gas price above the top of the 10-year range. 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 2025. Yellowtail entered service in August and progressed to ramp up throughout the fourth quarter achieving an average gross production of 240 kbd. The combined gross production from the four operating vessels exceeded 870 kbd in the fourth quarter of 2025. With start-up of a fourth vessel, Guyana achieved record annual production in 2025 of 715 kbd. Uaru, and Whiptail, the fifth and sixth developments on the Stabroek Block, respectively, are progressing on schedule and each has an investment basis capacity of approximately 250 kbd. In September 2025, ExxonMobil made a final investment decision for the Hammerhead development, after receiving the required regulatory approvals from the government of Guyana; Hammerhead is anticipated to come online in 2029. We anticipate eight FPSO vessels will be in operation on the Stabroek Block by year-end 2030.
Permian: ExxonMobil delivered strong and efficient growth in Permian production volumes in 2025. Total production volumes averaged a record 1.6 Moebd in 2025, approximately 0.4 Moebd 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 lightweight proppant as well as leading capabilities and technology in drilling and completions. ExxonMobil expects to increase production in the Permian Basin to approximately 2.5 Moebd by 2030. ExxonMobil remains on track to achieve Scope 1 and 2 net zero greenhouse gas emissions in the integrated Permian Basin operated assets by 2035.
LNG: ExxonMobil continued work on LNG growth projects in 2025. In Papua New Guinea (PNG), the Papua LNG project has been optimizing the development plan and enhancing project cost competitiveness. Force majeure was lifted in Mozambique, as the Rovuma LNG project continues with the front-end engineering and design stage, in support of a final investment decision in 2026 to develop the Area 4 offshore gas resources. Mechanical completion was achieved for the Golden Pass LNG project, with expected first LNG production in the first quarter of 2026.
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Upstream Financial Results
(millions of dollars)
Earnings (loss) (U.S. GAAP)
United States
Non-U.S.
Total
Identified Items (1)
United States
Non-U.S.
Total
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States
Non-U.S.
Total
2025 Upstream Earnings Driver Analysis (1)
(millions of dollars)
Price – Lower realizations decreased earnings by $6.1 billion, primarily driven by lower crude prices as record demand was more than offset by increased industry supply.
Advantaged Volume Growth – Increased earnings by $1.9 billion, mainly driven by record production in Permian and Guyana.
Base Volume – Decreased earnings by $0.7 billion as a result of non-strategic asset divestments.
Structural Cost Savings (1) – Increased earnings by $1.4 billion.
Expenses – Decreased earnings by $0.6 billion, primarily higher depreciation from the Tengiz expansion.
Other – Increased earnings by $0.6 billion, mainly driven by favorable tax and foreign exchange impacts.
Timing Effects – Favorable timing effects from derivatives mark-to-market impacts increased earnings by $0.6 billion.
Identified Items (1) – 2024 $0.2 billion gain mainly due to Argentina divestment, partly offset by Nigeria divestment and U.S. impairment; 2025 $(0.9) billion loss mainly due to asset impairments.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
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2024 Upstream Earnings Driver Analysis (1)
(millions of dollars)
Price – Price impacts decreased earnings by $1.3 billion, driven by lower gas realizations.
Advantaged Volume Growth – Higher volumes from advantaged assets increased earnings by $3.8 billion, 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 $0.8 billion.
Structural Cost Savings (1) – Increased earnings by $0.8 billion.
Expenses – Higher expenses decreased earnings by $1.4 billion, primarily from higher depreciation (non-cash).
Other – All other items increased earnings by $0.1 billion, 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 $0.3 billion.
Identified Items (1) – 2023 $(2.3) billion loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California; 2024 $0.2 billion gain mainly due to Argentina divestment, partly offset by Nigeria divestment and U.S. impairment.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, 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.
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Upstream Operational Results
Net production of crude oil, natural gas liquids, bitumen and synthetic oil
(thousands of barrels daily)
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Worldwide
Net natural gas production available for sale
(millions of cubic feet daily)
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Worldwide
Oil-equivalent production (1)
(thousands of oil-equivalent barrels daily)
(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)
Volumes Reconciliation (Oil-equivalent production) (1)
Prior Year
Entitlements - Net Interest
Entitlements - Price / Spend / Other
Government Mandates
Divestments
Growth / Other
Current Year
(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
2025 versus 2024
2025 production of 4.7 million oil-equivalent barrels per day increased 403 thousand barrels per day from 2024. Permian reached 1.6 million net oil-equivalent barrels per day and Guyana production exceeded 700 thousand gross 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 525 thousand oil-equivalent barrels per day.
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.
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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, aromatics, and NGL value chains, as well as 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 geopolitical 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 2025, refining margins increased from the prior year on record demand, but remained within the 10-year historical range (2010-2019). 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: Started up the project at the Strathcona refinery, which is designed to use low-carbon hydrogen, locally-sourced and grown feedstocks, and our proprietary catalyst to produce renewable diesel.
Fawley Hydrofiner project : Started up the project at the Fawley site to increase production of ultra-low sulfur diesel and reduce production of other products, including high-sulfur distillates.
France divestment: In November 2025, ExxonMobil completed the divestments of Esso Société Anonyme Française SA and ExxonMobil Chemical France SAS, including the refinery and related assets.
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Energy Products Financial Results
(millions of dollars)
Earnings (loss) (U.S. GAAP)
United States
Non-U.S.
Total
Identified Items (1)
United States
Non-U.S.
Total
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States
Non-U.S.
Total
Due to rounding, numbers presented may not add up precisely to the totals indicated.
2025 Energy Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Increased earnings by $1.8 billion, mainly driven by robust demand and supply disruptions.
Advantaged Volume Growth – Higher volumes from advantaged projects growth increased earnings by $0.2 billion.
Base Volume – Higher volumes driven by lower scheduled maintenance increased earnings by $0.4 billion.
Structural Cost Savings (1) – Increased earnings by $0.6 billion.
Expenses – Decreased earnings by $0.5 billion, mainly driven by growth projects.
Other – Increased earnings by $0.2 billion mainly from favorable year-end inventory effects.
Timing Effects – Favorable timing effects from derivatives mark-to-market impacts increased earnings by $0.4 billion.
Identified Items (1) – 2024 $0.1 billion gain; 2025 $0.5 billion gain mainly driven by asset sales.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
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2024 Energy Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Significantly weaker industry refining margins decreased earnings by $6.3 billion. 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 $0.1 billion.
Base Volume – Lower base volumes decreased earnings by $1.2 billion driven by scheduled maintenance and divestments.
Structural Cost Savings (1) – Increased earnings by $0.6 billion.
Expenses – Higher expenses related to scheduled turnarounds and maintenance, and advantaged project spend decreased earnings by $1.0 billion.
Other – All other items, mainly unfavorable tax and forex impacts, decreased earnings by $0.3 billion.
Timing Effects – Decreased earnings by $10 million.
Identified Items (1) – 2023 $0.1 billion gain driven by favorable tax effects partially offset by additional European taxes on the energy sector; 2024 $0.1 billion gain.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
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Energy Products Operational Results
(thousands of barrels daily)
Refinery throughput
United States
Canada
Europe
Asia Pacific
Other
Worldwide
Energy Products sales (1)
United States
Non-U.S.
Worldwide
Gasoline, naphthas
Heating oils, kerosene, diesel
Aviation fuels
Heavy fuels
Other energy products
Worldwide
(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 overall 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 2025, chemical industry margins remained deeply bottom-of-cycle, below the 10-year historical range (2010-2019), as capacity additions have far exceeded demand growth. The Company optimized production across our global footprint to profitably meet customer demand. Our earnings benefited from solid reliability, record high-value products sales, and a large North American footprint where low ethane prices continue to provide a feed advantage.
Key Recent Events
China Chemical Complex: Started up 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 is the first 100 percent foreign-owned petrochemical complex built in China. The facility, which focuses on producing our unique high-performance polyethylene and polypropylene products, is equipped with 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 large and evolving 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 back into raw materials to produce valuable new products. In 2025, the Company added two new advanced recycling units to the Baytown facility, tripling capacity at the site, and representing one of the largest advanced recycling facilities in North America. Additional units are being assessed as the Company aims to reach a global recycling capacity of 1 billion pounds per year to help reduce plastic waste.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Chemical Products Financial Results
(millions of dollars)
Earnings (loss) (U.S. GAAP)
United States
Non-U.S.
Total
Identified Items (1)
United States
Non-U.S.
Total
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States
Non-U.S.
Total
2025 Chemical Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Decreased earnings by $1.8 billion, as oversupply resulted in margins at bottom-of-cycle market conditions.
Advantaged Volume Growth – New projects increased earnings by $0.2 billion driven by high-value product sales.
Base Volume – Increased earnings by $0.1 billion.
Structural Cost Savings (1) – Increased earnings by $0.2 billion.
Expenses – Higher advantaged project spend, including China Chemical Complex ramp-up, decreased earnings by $0.5 billion.
Other – Increased earnings by $0.2 billion.
Identified Items (1) – 2024 $(0.1) billion loss driven by impairments; 2025 $(0.3) billion loss driven by impairments.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
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2024 Chemical Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Improved company margins on North American ethane feed advantage and improved product realizations increased earnings by $0.9 billion, despite continued bottom-of-cycle market conditions.
Advantaged Volume Growth – Record high-value product sales increased earnings by $0.4 billion.
Base Volume – Portfolio optimization and product sales mix decreased earnings by $0.3 billion.
Structural Cost Savings (1) – Increased earnings by $0.2 billion.
Expenses – Higher advantaged projects spend and inflation effects decreased earnings by $0.5 billion.
Other – All other items decreased earnings by $0.1 billion.
Identified Items (1) – 2023 $(0.4) billion loss was primarily driven by impairments; 2024 $(0.1) billion loss driven by impairments.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
Chemical Products Operational Results
(thousands of metric tons)
Chemical Products sales (2)
United States
Non-U.S.
Worldwide
(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.
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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 the demand for premium lubricant products through advantaged projects that leverage ExxonMobil's integration, technology, and world-class brands, such as Mobil 1 TM .
In 2025, 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: This project started up in 2025, leveraging two proprietary technologies to upgrade fuel oil to Group II lubricant basestock and diesel. It further strengthens ExxonMobil’s position as the largest basestock producer in the world and introduces a first-of-its-kind basestock, EHC 340 MAX TM , with superior performance attributes, to the market.
Proxxima TM Resin 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. In 2025, ExxonMobil more than tripled Proxxima TM resin blending capacity with plans to grow production 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 available capacity, 30 percent faster charging time, and extended battery life. In 2025, ExxonMobil acquired key technology and assets from Superior Graphite. This acquisition, which complements ExxonMobil's process technology and expertise, enables a faster scale-up and a swifter entry into the battery anode market with our differentiated graphite product.
Specialty Products Financial Results
(millions of dollars)
Earnings (loss) (U.S. GAAP)
United States
Non-U.S.
Total
Identified Items (1)
United States
Non-U.S.
Total
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States
Non-U.S.
Total
(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.
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2025 Specialty Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Increased earnings by $40 million.
Advantaged Volume Growth – Increased earnings by $0.1 billion.
Base Volume – Decreased earnings by $20 million.
Structural Cost Savings (1) – Increased earnings by $0.1 billion.
Expenses – Higher expenses to develop markets for carbon materials and Proxxima TM resins decreased earnings by $0.2 billion.
Other – Decreased earnings by $0.2 billion, mainly from unfavorable foreign exchange effects.
Identified Items (1) – 2024 $(13) million loss.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
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2024 Specialty Products Earnings Driver Analysis (1)
(millions of dollars)
Margin – Stronger basestocks and finished lubes margins increased earnings by $0.6 billion.
Advantaged Volume Growth – High-value product volume growth increased earnings by $0.1 billion.
Base Volume – Decreased earnings by $10 million.
Structural Cost Savings (1) – Increased earnings by $0.1 billion.
Expenses – Higher expenses including new product development costs, decreased earnings by $0.3 billion.
Other – All other items decreased earnings by $0.2 billion, mainly unfavorable foreign exchange effects and absence of prior year favorable year-end inventory effects.
Identified Items (1) – 2023 $(93) million loss from impairments; 2024 $(13) million loss.
(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.
Specialty Products Operational Results
(thousands of metric tons)
Specialty Products sales (2)
United States
Non-U.S.
Worldwide
(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.
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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)
Earnings (loss) (U.S. GAAP)
Identified Items (1)
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
(1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items.
Corporate and Financing expenses were $3.6 billion in 2025 compared to $1.4 billion in 2024, with the increase mainly due to higher financing costs.
Corporate and Financing expenses were $1.4 billion in 2024 compared to $1.8 billion in 2023, with the decrease mainly due to lower financing costs.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
(millions of dollars)
Net cash provided by/(used in)
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes
Increase/(decrease) in cash and cash equivalents
Total cash and cash equivalents (December 31)
Total cash and cash equivalents were $10.7 billion at the end of 2025, down $12.5 billion from the prior year. The major sources of funds in 2025 were net income including noncontrolling interests of $29.8 billion, the adjustment for the noncash provision of $26.0 billion for depreciation and depletion, proceeds from asset sales of $3.2 billion, and other investing activities of $3.4 billion. The major uses of funds included spending for additions to property, plant, and equipment of $28.4 billion; dividends to shareholders of $17.2 billion; the purchase of ExxonMobil stock of $20.3 billion ; additional investments and advances of $4.1 billion; and a change in working capital of $7.7 billion.
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, and 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 a change in working capital of $1.8 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. Commercial paper is used to balance short-term liquidity requirements and is reflected in "Notes and loans payable" on the Consolidated Balance Sheet, with changes in outstanding commercial paper between periods included in the Consolidated Statement of Cash Flows. On December 31, 2025, the Corporation had undrawn short-term committed lines of credit of $7.3 billion and undrawn long-term lines of credit of $1.0 billion. In the fourth quarter of 2025, the Corporation established a 364-day revolving credit facility of $7.0 billion to provide short-term borrowing capacity for general corporate purposes.
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 2025 was $29.0 billion, including $2.6 billion of acquisitions, reflecting the Corporation’s continued active investment program.
Upstream spending of $24.7 billion in 2025 was up $4.4 billion from 2024, reflecting higher spend in the U.S. Permian Basin which included the full-year impact from 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 64 percent of total proved reserves at year-end 2025 and has been over 60 percent for the last ten years.
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Capital investments in the three Product Solutions businesses totaled $3.7 billion in 2025, a decrease of $0.8 billion from 2024, reflecting lower global project spending. Other spend of $0.6 billion primarily reflects investments in the Low Carbon Solutions business.
The Corporation plans to invest in the range of $27 billion to $29 billion in 2026. The investment range for 2026 excludes advances and collections not related to capital expenditures or equity investments, for example, supply and marketing related advances and associated collections. Included in the 2026 capital spend range is $8.5 billion of firm capital commitments. An additional $8.0 billion of firm capital commitments have been made for years 2027 and beyond. 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.
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
Cash provided by operating activities totaled $52.0 billion in 2025, $3.1 billion lower than 2024. The major source of funds was net income including noncontrolling interests of $29.8 billion, a decrease of $5.3 billion. The noncash provision for depreciation and depletion was $26.0 billion, up $2.6 billion from the prior year. The adjustment for the net gain on asset sales was $1.1 billion, a decrease of $0.1 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $3.0 billion, compared to an increase of $0.2 billion in 2024. Changes in operational working capital, excluding cash and debt, decreased cash in 2025 by $7.7 billion.
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.
Cash Flow from Investing Activities
Cash used in investing activities netted to $25.9 billion in 2025, $6.0 billion higher than 2024. Spending for property, plant, and equipment of $28.4 billion increased $4.1 billion from 2024. Proceeds from asset sales and returns of investments of $3.2 billion compared to $5.0 billion in 2024. Additional investments and advances were $0.8 billion higher in 2025, while proceeds from other investing activities including collection of advances increased by $1.5 billion.
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.
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Cash Flow from Financing Activities
Cash used in financing activities was $39.1 billion in 2025, $3.7 billion lower than 2024. Dividend payments on common shares increased to $4.00 per share from $3.84 per share and totaled $17.2 billion.
During 2025, the Corporation continued its share repurchase program, including the purchase of 180.1 million shares at a book value of $20 billion in 2025. In its 2025 Corporate Plan Update released December 9, 2025, 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 p articular 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.
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.
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 4 , 9 , 12 , and 13 for information related to pensions, asset retirement obligations, long-term debt, and leases, respectively.
In addition, the Corporation also enters into commodity purchase obligations (volumetric commitments with 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 2025 for take-or-pay and unconditional purchase obligations was $54.1 billion. Cash payments expected in 2026 and 2027 are $6.3 billion and $6.2 billion, respectively.
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2025, for guarantees relating to notes, loans, and performance under contracts ( Note 7 ). 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.
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Financial Strength
On December 31, 2025, the Corporation had total unused short-term committed lines of credit of $7.3 billion ( Note 10 ) and total unused long-term committed lines of credit of $1.0 billion ( Note 12 ). The table below shows the Corporation’s consolidated debt to capital ratios.
(percent)
Debt to capital
Net debt to capital (1)
(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 2025, ending the year at $43.5 billion.
Litigation and Other Contingencies
As discussed in Note 7 , 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 7 for additional information on legal proceedings and other contingencies.
TAXES
(millions of dollars)
Income taxes
Effective income tax rate
Total other taxes and duties
Total
Total taxes on the Corporation’s income statement were $40.4 billion in 2025, a decrease of $3.3 billion from 2024. Income tax expense, both current and deferred, was $11.5 billion compared to $13.8 billion in 2024. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 31 percent. This is down two percentage points compared to 2024 due primarily to favorable one-time items. Total other taxes and duties of $28.9 billion in 2025 decreased $1.0 billion.
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 is flat compared to 2023. Total other taxes and duties of $29.9 billion in 2024 decreased $2.3 billion from 2023.
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ENVIRONMENTAL MATTERS
Environmental Expenditures
(millions of dollars)
Capital expenditures
Other expenditures
Total
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 2025 worldwide environmental expenditures for all such preventative and remediation steps were $7.6 billion, of which $4.6 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 $9 billion annually in 2026 and 2027, with capital expenditures expected to account for approximately 44 percent of the total expenditures.
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 2025 for environmental liabilities were $0.4 billion ($0.3 billion in 2024), and the balance sheet reflects liabilities of $0.9 billion as of December 31, 2025, and $0.7 billion as of December 31, 2024.
MARKET RISKS
Worldwide Average Realizations (1)
Brent ($ per barrel)
Henry Hub ($ per metric million British thermal unit)
TTF ($ per metric million British thermal unit)
(1) Consolidated subsidiaries.
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 2026, a $1 per barrel change in the Brent price would have an approximately $700 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 $90 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.
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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 3 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, 2025 and 2024, or results of operations for the years ended 2025, 2024, and 2023. 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 6 . The Corporation maintains a system of controls that includes the authorization, reporting, and monitoring of derivative activity.
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 and ammonia, lower-emission fuels, Proxxima TM resin systems, carbon materials, low-carbon data centers, 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 .
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 judgment 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 Note 20 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 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 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from its Permian Basin operated 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.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2025 totaled $2.0 billion after-tax, including a write-down to fair value of Upstream oil and gas assets held for sale and charges associated with the optimization of materials and supply inventory.
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.
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 property, plant, and equipment and suspended wells, refer to Notes 9 and 16 , 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.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pension Benefits
The Corporation and its affiliates sponsor about 70 defined benefit (pension) plans in nearly 40 countries. Note 4 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 2025 was 6.0 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 5 percent over both periods. 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 $150 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.
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 7 , 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.
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 15 .
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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, 2025.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2025, as stated in their report included in the Financial Section of this report.
Darren W. Woods
Chief Executive Officer
Neil A. Hansen
Senior Vice President and
Chief Financial Officer
Len M. Fox
Vice President, Controller and Tax
(Principal Accounting Officer)
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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, 2025 and 2024, 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, 2025, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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.
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.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Developed Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net
As described in Notes 1 , 3 , and 9 to the consolidated financial statements, the Corporation's consolidated upstream property, plant, and equipment (PP&E), net balance was $228.2 billion as of December 31, 2025, and the related depreciation and depletion expense was $21.4 billion for the year ended December 31, 2025. 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, which are derived using historical production volumes, and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, specifically historical production volumes, 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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 18, 2026
We have served as the Corporation’s auditor since 1934.
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The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF INCOME
(millions of dollars)
Note
Reference
Number
Revenues and other income
Sales and other operating revenue
Income from equity affiliates
Other income
Total revenues and other income
Costs and other deductions
Crude oil and product purchases
Production and manufacturing expenses
Selling, general and administrative expenses
Depreciation and depletion (includes impairments)
Exploration expenses, including dry holes
Non-service pension and postretirement benefit expense
Interest expense
Other taxes and duties
Total costs and other deductions
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss) including noncontrolling interests
Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to ExxonMobil
Earnings (loss) per common share (dollars)
Earnings (loss) per common share - assuming dilution (dollars)
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The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(millions of dollars)
Net income (loss) including noncontrolling interests
Other comprehensive income (loss) (net of income taxes)
Foreign exchange translation adjustment
Adjustment for foreign exchange translation (gain)/loss included in net income
Postretirement benefits reserves adjustment (excluding amortization)
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs
Total other comprehensive income (loss)
Comprehensive income (loss) including noncontrolling interests
Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive income (loss) attributable to ExxonMobil
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The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED BALANCE SHEET
(millions of dollars)
Note
Reference
Number
December 31, 2025
December 31, 2024
ASSETS
Current assets
Cash and cash equivalents
Cash and cash equivalents – restricted
Notes and accounts receivable – net
Inventories
Crude oil, products and merchandise
Materials and supplies
Other current assets
Total current assets
Investments, advances, and long-term receivables
Property, plant, and equipment, at cost, less accumulated depreciation and depletion
Other assets, including intangibles – net
Total Assets
LIABILITIES
Current liabilities
Notes and loans payable
Accounts payable and accrued liabilities
Income taxes payable
Total current liabilities
Long-term debt
Postretirement benefits reserves
Deferred income tax liabilities
Long-term obligations to equity companies
Other long-term obligations
Total Liabilities
Commitments and contingencies
EQUITY
Common stock without par value
( 9,000 million shares authorized, 8,019 million shares issued)
Earnings reinvested
Accumulated other comprehensive income
Common stock held in treasury
( 3,840 million shares in 2025 and 3,666 million shares in 2024)
ExxonMobil share of equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
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The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(millions of dollars)
Note Reference Number
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) including noncontrolling interests
Adjustments for noncash transactions
Depreciation and depletion (includes impairments)
Deferred income tax charges/(credits)
Postretirement benefits expense in excess of/(less than) net payments
Other long-term obligation provisions in excess of/(less than) payments
Dividends received greater than/(less than) equity in current earnings of equity companies
Changes in operational working capital, excluding cash and debt
Notes and accounts receivable reduction/(increase)
Inventories reduction/(increase)
Other current assets reduction/(increase)
Accounts and other payables increase/(reduction)
Net (gain)/loss on asset sales
All other items - net
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, and equipment
Proceeds from asset sales and returns of investments
Additional investments and advances
Other investing activities including collection of advances
Cash acquired from mergers and acquisitions
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Additions to long-term debt (1)
Reductions in long-term debt
Additions to short-term debt (2) (3)
Reductions in short-term debt (3)
Additions/(reductions) in commercial paper, and debt with three months or less maturity
Contingent consideration payments
Cash dividends to ExxonMobil shareholders
Cash dividends to noncontrolling interests
Changes in noncontrolling interests
Inflows from noncontrolling interests for major projects
Common stock acquired
Net cash provided by (used in) financing activities
Effects of exchange rate changes on cash
Increase/(decrease) in cash and cash equivalents (including restricted)
Cash and cash equivalents at beginning of year (including restricted)
Cash and cash equivalents at end of year (including restricted)
(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.
(2) Includes $ 659 million of proceeds related to a financing arrangement to facilitate the sale of an entity where the buyer assumed the obligation at closing; no longer on the Consolidated Balance Sheet at the end of 2025.
(3) Includes commercial paper with a maturity greater than three months.
Non-Cash Transaction: The Corporation acquired Pioneer Natural Resources Company 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 and assumed debt with a fair value of $ 5 billion. See Note 20 for additional information.
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The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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, 2022
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Other comprehensive income
Share repurchases, at cost
Issued for acquisitions
Dispositions
Balance as of December 31, 2023
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Other comprehensive income
Share repurchases, at cost
Issued for acquisitions
Dispositions
Balance as of December 31, 2024
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Other comprehensive income
Share repurchases, at cost
Dispositions
Balance as of December 31, 2025
Common Stock Share Activity
(millions of shares)
Issued
Held in
Treasury
Outstanding
Balance as of December 31, 2022
Share repurchases, at cost
Issued for acquisitions
Dispositions
Balance as of December 31, 2023
Share repurchases, at cost
Issued for acquisitions
Dispositions
Balance as of December 31, 2024
Share repurchases, at cost
Issued for acquisitions
Dispositions
Balance as of December 31, 2025
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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 and ammonia, lower-emission fuels, Proxxima TM resin systems, carbon materials, low-carbon data centers, 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.
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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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from its operated assets in the Permian Basin 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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Earnings Per Share
Earnings per common share
Net income (loss) attributable to ExxonMobil (millions of dollars)
Weighted-average number of common shares outstanding (millions of shares) (1)
Earnings (loss) per common share (dollars) (2)
Dividends paid per common share (dollars)
(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.
Note 3. Disclosures about Segments and Related Information
Our four 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 $ 0.3 billion in 2025, $ 0.4 billion in 2024, and $ 0.2 billion in 2023.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(millions of dollars)
Upstream
Energy Products
Chemical Products
Specialty Products
Segment Total
Non-U.S.
Non-U.S.
Non-U.S.
Non-U.S.
Year ended December 31, 2025
Revenues and other income
Sales and other operating revenue
Income from equity affiliates
Intersegment revenue
Other income
Segment revenues and other income
Costs and other items
Crude oil and product purchases
Operating expenses, excl. depreciation and depletion (1)
Depreciation and depletion (includes impairments)
Interest expense
Other taxes and duties
Total costs and other deductions
Segment income (loss) before income taxes
Income tax expense (benefit)
Segment net income (loss) incl. noncontrolling interests
Net income (loss) attributable to noncontrolling interests
Segment income (loss)
Reconciliation of consolidated revenues
Segment revenues and other income
Other revenues (2)
Elimination of intersegment revenues
Total consolidated revenues and other income
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss)
Corporate and Financing income (loss)
Net income (loss) attributable to ExxonMobil
(millions of dollars)
Upstream
Energy Products
Chemical Products
Specialty Products
Segment Total
Non-U.S.
Non-U.S.
Non-U.S.
Non-U.S.
As of December 31, 2025
Additions to property, plant, and equipment (3)
Investments in equity companies
Total assets
Reconciliation to Corporate Total
Segment Total
Corporate and Financing
Corporate Total
Additions to property, plant, and equipment (3)
Investments in equity companies
Total assets
(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 $ 1,212 million.
(3) Includes non-cash additions.
Due to rounding, numbers presented may not add up precisely to the totals indicated.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(millions of dollars)
Upstream
Energy Products
Chemical Products
Specialty Products
Segment Total
Non-U.S.
Non-U.S.
Non-U.S.
Non-U.S.
Year ended December 31, 2024
Revenues and other income
Sales and other operating revenue
Income from equity affiliates
Intersegment revenue
Other income
Segment revenues and other income
Costs and other items
Crude oil and product purchases
Operating expenses, excl. depreciation and depletion (1)
Depreciation and depletion (includes impairments)
Interest expense
Other taxes and duties
Total costs and other deductions
Segment income (loss) before income taxes
Income tax expense (benefit)
Segment net income (loss) incl. noncontrolling interests
Net income (loss) attributable to noncontrolling interests
Segment income (loss)
Reconciliation of consolidated revenues
Segment revenues and other income
Other revenues (2)
Elimination of intersegment revenues
Total consolidated revenues and other income
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss)
Corporate and Financing income (loss)
Net income (loss) attributable to ExxonMobil
(millions of dollars)
Upstream
Energy Products
Chemical Products
Specialty Products
Segment Total
Non-U.S.
Non-U.S.
Non-U.S.
Non-U.S.
As of December 31, 2024
Additions to property, plant, and equipment (3)
Investments in equity companies
Total assets
Reconciliation to Corporate Total
Segment Total
Corporate and Financing
Corporate Total
Additions to property, plant, and equipment (3)
Investments in equity companies
Total assets
(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 20 for additions resulting from the Pioneer acquisition in 2024.
Due to rounding, numbers presented may not add up precisely to the totals indicated.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(millions of dollars)
Upstream
Energy Products
Chemical Products
Specialty Products
Segment Total
Non-U.S.
Non-U.S.
Non-U.S.
Non-U.S.
Year ended December 31, 2023
Revenues and other income
Sales and other operating revenue
Income from equity affiliates
Intersegment revenue
Other income
Segment revenues and other income
Costs and other items
Crude oil and product purchases
Operating expenses, excl. depreciation and depletion (1)
Depreciation and depletion (includes impairments)
Interest expense
Other taxes and duties
Total costs and other deductions
Segment income (loss) before income taxes
Income tax expense (benefit)
Segment net income (loss) incl. noncontrolling interests
Net income (loss) attributable to noncontrolling interests
Segment income (loss)
Reconciliation of consolidated revenues
Segment revenues and other income
Other revenues (2)
Elimination of intersegment revenues
Total consolidated revenues and other income
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss)
Corporate and Financing income (loss)
Net income (loss) attributable to ExxonMobil
(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.
Due to rounding, numbers presented may not add up precisely to the totals indicated.
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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)
Revenue from contracts with customers
Revenue outside the scope of ASC 606
Total
Geographic
Sales and other operating revenue
(millions of dollars)
United States
Non-U.S.
Total
Significant non-U.S. revenue sources include: (1)
Canada
(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,
United States
Non-U.S.
Total
Significant non-U.S. long-lived assets include:
Canada
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Note 4. 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)
Non-U.S.
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate (percent)
Long-term rate of compensation increase (percent)
Change in benefit obligation
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss/(gain) (1)
Benefits paid (2)(3)
Foreign exchange rate changes
Amendments, divestments and other (5)(6)
Benefit obligation at December 31
Accumulated benefit obligation at December 31
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 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 2027 and subsequent years.
Pension Benefits
Other Postretirement Benefits
(millions of dollars)
Non-U.S.
Change in plan assets
Fair value at January 1
Actual return on plan assets
Foreign exchange rate changes
Company contribution
Benefits paid (4)
Other (5)(6)
Fair value at December 31
(1) Actuarial loss/(gain) primarily reflects a lower discount rate in the U.S. and generally higher discount rates outside of the U.S.
(2) Benefit payments for funded and unfunded plans.
(3) For 2024, other postretirement benefits paid are net of $ 10 million of Medicare subsidy receipts.
(4) Benefit payments for funded plans.
(5) The U.S. ExxonMobil Pension Plan purchased a group annuity contract from an insurer in 2025 for $ 767 million to transfer obligations to pay future benefits. The transaction did not change the amount of pension benefits payable to transferred participants and did not require additional funding from the plan.
(6) Non-U.S. includes benefit obligation and plan asset reductions in 2025 of $ 1,059 million and $ 642 million, respectively, resulting from the divestment of Product Solutions affiliates in France.
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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)
Non-U.S.
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans
Unfunded plans
Total
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)
Non-U.S.
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1)
Amounts recorded in the Consolidated Balance Sheet consist of:
Other assets
Current liabilities
Postretirement benefits reserves
Total recorded
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)
Prior service cost
Total recorded in accumulated other comprehensive income
(1) Fair value of assets less benefit obligation shown on the preceding page.
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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)
Non-U.S.
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
Discount rate (percent)
Long-term rate of return on funded assets (percent)
Long-term rate of compensation increase (percent)
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss/(gain)
Amortization of prior service cost
Net pension enhancement and curtailment/settlement cost
Net periodic benefit cost
Changes in amounts recorded in accumulated other comprehensive income:
Net actuarial loss/(gain)
Amortization of actuarial (loss)/gain
Prior service cost/(credit)
Amortization of prior service (cost)/credit
Foreign exchange rate changes
Total recorded in other comprehensive income
Total recorded in net periodic benefit cost and other comprehensive income, before tax
Costs for defined contribution plans were $ 0.4 billion, $ 0.4 billion, and $ 0.4 billion in 2025, 2024, and 2023, respectively.
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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)
(Charge)/credit to other comprehensive income, before tax
U.S. pension
Non-U.S. pension
Other postretirement benefits
Total (charge)/credit to other comprehensive income, before tax
(Charge)/credit to income tax (see Note 5 )
(Charge)/credit to investment in equity companies
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax
Charge/(credit) to equity of noncontrolling interests
(Charge)/credit to other comprehensive income attributable to ExxonMobil
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 5 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.
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The 2025 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, 2025, Using:
Fair Value Measurement at
December 31, 2025, 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
Non-U.S.
Private equity
Debt securities
Corporate
Government
Asset-backed
Other
Real Estate
Cash
Other
Total at fair value
Insurance contracts at contract value
Total plan assets
(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, 2025, Using:
Level 1
Level 2
Level 3
Net Asset Value
Total
Asset category:
Equity securities
Non-U.S.
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
(5) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(6) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
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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
Non-U.S.
Private equity
Debt securities
Corporate
Government
Asset-backed
Other
Real Estate
Cash
Other
Total at fair value
Insurance contracts at contract value
Total plan assets
(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
Non-U.S.
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
(5) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(6) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
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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)
Non-U.S.
For funded pension plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation
Fair value of plan assets
For funded pension plans with a projected benefit obligation in
excess of plan assets:
Projected benefit obligation
Fair value of plan assets
For unfunded pension plans:
Projected benefit obligation
Accumulated benefit obligation
All other postretirement benefit plans are unfunded or underfunded.
Pension Benefits
Other Postretirement Benefits
(millions of dollars)
Non-U.S.
Gross
Medicare Subsidy Receipt
Contributions expected in 2026
Benefit payments expected in:
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Note 5. 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, 2022
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2023
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2024
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2025
(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) net of taxes of $( 294 ) million, $ 196 million, and $( 135 ) million in 2025, 2024, and 2023, respectively.
Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)
(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
(Statement of Income line: Other income)
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)
Income Tax (Expense)/Credit For
Components of Other Comprehensive Income
(millions of dollars)
Foreign exchange translation adjustment
Postretirement benefits reserves adjustment (excluding amortization)
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs
Total
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Note 6. Financial Instruments and Derivatives
The estimated fair value of financial instruments and derivatives at December 31, 2025, and December 31, 2024, and the related hierarchy level for the fair value measurement was as follows:
December 31, 2025
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)
Advances to/receivables from equity
companies (2)(6)
Other long-term financial assets (3)
Liabilities
Derivative liabilities (4)
Long-term debt (5)
Long-term obligations to equity companies (6)
Other long-term financial liabilities (7)
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)
Advances to/receivables from equity
companies (2)(6)
Other long-term financial assets (3)
Liabilities
Derivative liabilities (4)
Long-term debt (5)
Long-term obligations to equity companies (6)
Other long-term financial liabilities (7)
(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, 2025, and December 31, 2024, respectively, the Corporation had $ 0.5 billion and $ 0.5 billion of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements.
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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” and included before-tax realized and unrealized gains of $ 1.1 billion, losses of $ 0.7 billion, and gains of $ 1.0 billion in 2025, 2024, and 2023, respectively. 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, 2025 and 2024, or results of operations for 2025, 2024, and 2023.
The Corporation operates 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.
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, 2025, and December 31, 2024, was as follows:
(millions)
December 31,
December 31,
Crude oil (barrels)
Petroleum products (barrels)
Natural gas (MMBTUs)
Note 7. 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2025, 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, 2025
(millions of dollars)
Equity Company Obligations (1)
Other Third-Party Obligations
Total
Guarantees
Non-debt-related
Total
(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.
Note 8. 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 10 percent, 9 percent, and 9 percent in 2025, 2024, and 2023, 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)
Total
ExxonMobil
Share
Total
ExxonMobil Share
Total
ExxonMobil
Share
Total revenues
Income before income taxes
Income taxes
Income from equity affiliates
Current assets
Long-term assets
Total assets
Current liabilities
Long-term liabilities
Net assets
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A list of significant equity companies as of December 31, 2025, together with the Corporation’s percentage ownership interest, is detailed below:
Percentage Ownership Interest
Upstream
Barzan Gas Company Limited
BEB Erdgas und Erdoel GmbH & Co. KG
Caspian Pipeline Consortium
Coral FLNG S.A.
Cross Timbers Energy LLC
GasTerra B.V.
Golden Pass LNG Terminal LLC
Golden Pass Pipeline LLC
Marine Well Containment Company LLC
Mozambique Rovuma Venture S.p.A.
Nederlandse Aardolie Maatschappij B.V.
Papua New Guinea Liquefied Natural Gas Global Company LDC
Permian Highway Pipeline LLC
QatarEnergy LNG N (2)
QatarEnergy LNG NFE (3)
QatarEnergy LNG S (2)
QatarEnergy LNG S (3)
South Hook LNG Terminal Company Limited
Tengizchevroil LLP
Energy Products, Chemical Products, and/or Specialty Products
Al-Jubail Petrochemical Company
Alberta Products Pipe Line Ltd.
Fujian Refining & Petrochemical Co. Ltd.
Gulf Coast Growth Ventures LLC
Infineum USA L.P.
Permian Express Partners LLC
Saudi Aramco Mobil Refinery Company Ltd.
Saudi Yanbu Petrochemical Co.
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Note 9. Property, Plant, and Equipment and Asset Retirement Obligations
Property, Plant, and Equipment
(millions of dollars)
December 31, 2025
December 31, 2024
Cost
Net
Cost
Net
Upstream
Energy Products
Chemical Products
Specialty Products
Other
Total
In 2025, 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. The Corporation recognized before-tax impairment charges of $ 1.6 billion in Upstream, $ 0.1 billion in Chemical Products, and $ 0.3 billion in Other.
In 2024, before-tax impairment charges recognized 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.
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 $ 270,686 million at the end of 2025 and $ 259,585 million at the end of 2024.
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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)
Balance at January 1
Accretion expense and other provisions
Reduction due to property sales
Payments made
Liabilities incurred
Foreign currency translation
Revisions
Balance at December 31
The long-term Asset Retirement Obligations were $ 11.3 billion and $ 10.9 billion at December 31, 2025 and 2024, respectively, and are included in “Other long-term obligations” on the Consolidated Balance Sheet. Estimated cash payments in 2026 and 2027 are $ 1.3 billion and $ 1.5 billion, respectively.
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Note 10. Additional Working Capital Information
(millions of dollars)
Dec 31, 2025
Dec 31, 2024
Notes and accounts receivable
Trade, less reserves of $ 270 million and $ 162 million
Other, less reserves of $ 170 million and $ 314 million
Total
Notes and loans payable
Bank loans
Commercial paper
Long-term debt due within one year
Total
Accounts payable and accrued liabilities
Trade payables
Payables to equity companies
Accrued taxes other than income taxes
Other
Total
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 $ 7.3 billion which were unused as of December 31, 2025. These lines of credit are available for general corporate purposes.
The weighted-average interest rate on short-term borrowings outstanding was 3.8 percent at December 31, 2025.
Note 11. Investments, Advances, and Long-Term Receivables
(millions of dollars)
Dec 31, 2025
Dec 31, 2024
Equity method company investments and advances
Investments
Advances, net of allowances of $ 33 million and $ 40 million
Total equity method company investments and advances
Equity securities carried at fair value and other investments at adjusted cost basis
Long-term receivables and miscellaneous, net of reserves of $ 2,500 million and $ 2,433 million
Total
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Note 12. Long-Term Debt
At December 31, 2025, long-term debt consisted of $ 26.4 billion due in U.S. dollars and $ 7.8 billion 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 $ 6.2 billion, 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, 2026, are: 2027 – $ 2.5 billion; 2028 – $ 1.7 billion; 2029 – $ 1.7 billion; and 2030 – $ 5.3 billion. At December 31, 2025, the Corporation's unused long-term lines of credit were $ 1.0 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, 2025, the Corporation has designated its $ 3.5 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized long-term debt at year-end 2025 and 2024 are shown in the table below:
(millions of dollars, except where stated otherwise)
Average
Rate (1)
Dec 31, 2025
Dec 31, 2024
Exxon Mobil Corporation (2)(3)
3.043 % notes due 2026
2.275 % notes due 2026
3.294 % notes due 2027
2.440 % notes due 2029
3.482 % notes due 2030
2.610 % notes due 2030
2.995 % notes due 2039
4.227 % notes due 2040
3.567 % notes due 2045
4.114 % notes due 2046
3.095 % notes due 2049
4.327 % notes due 2050
3.452 % notes due 2051
Exxon Mobil Corporation - Euro-denominated
0.524 % notes due 2028
0.835 % notes due 2032
1.408 % notes due 2039
XTO Energy Inc. (4)
6.100 % senior notes due 2036
6.750 % senior notes due 2037
6.375 % senior notes due 2038
Pioneer Natural Resources Company (5)
1.125 % senior notes due 2026
5.100 % senior notes due 2026
7.200 % senior notes due 2028
1.900 % senior notes due 2030
2.150 % senior notes due 2031
Parsley Energy LLC (6)
4.125 % senior notes due 2028
Industrial revenue bonds due 2026-2051
Finance leases & other obligations
Debt issuance costs
Total long-term debt
(1) Average effective or imputed interest rates at December 31, 2025.
(2) Includes impacts of hedge accounting of interest rate swaps.
(3) Includes premiums of $ 72 million in 2025 and $ 76 million in 2024.
(4) Includes premiums of $ 60 million in 2025and $ 66 million in 2024.
(5) Includes net discounts of $ 267 million in 2025 and $ 348 million in 2024.
(6) Includes discounts of $ 5 million in 2025 and $ 7 million in 2024.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13. 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, 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
Operating lease cost
Short-term and other (net of sublease rental income)
Amortization of right of use assets
Interest on lease liabilities
Total (1)
(1) Includes $ 984 million, $ 1,195 million, and $ 999 million for drilling rigs and related equipment operating leases in 2025, 2024, and 2023, respectively.
Balance Sheet
(millions of dollars)
Operating Leases
Finance Leases
December 31, 2025
December 31, 2024
December 31, 2025
December 31, 2024
Right of use assets
Included in Other assets, including intangibles - net
Included in Property, plant, and equipment - net
Total right of use assets
Lease liability due within one year
Included in Accounts payable and accrued liabilities
Included in Notes and loans payable
Long-term lease liability
Included in Other long-term obligations
Included in Long-term debt
Included in Long-term obligations to equity companies
Total lease liability (2)
Weighted-average remaining lease term (years)
Weighted-average discount rate (percent)
(2) Includes $ 1,691 million and $ 2,198 million for drilling rigs and related equipment operating leases in 2025 and 2024, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Maturity Analysis of Lease Liabilities
(millions of dollars)
Operating Leases
Finance Leases
December 31, 2025
2031 and beyond
Total lease payments
Discount to present value
Total lease liability
In addition to the lease liabilities in the table immediately above, at December 31, 2025, undiscounted commitments for leases not yet commenced totaled $ 3.0 billion for operating leases and $ 0.8 billion for finance leases. Estimated cash payments for operating and finance leases not yet commenced are $ 0.2 billion and $ 0.3 billion for 2026 and 2027 respectively. Operating leases not yet commenced primarily relate to LNG transportation vessels.
Other Information
(millions of dollars)
Operating Leases
Finance Leases
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Noncash right of use assets recorded for lease liabilities
In exchange for lease liabilities during the period
Note 14. Miscellaneous Financial Information
Research and development expenses totaled $ 1.2 billion in 2025, $ 1.0 billion in 2024, and $ 0.9 billion in 2023.
Net income included before-tax aggregate foreign exchange transaction gains/(losses) of $ 0.2 billion, $( 0.5 ) billion, and $( 0.1 ) billion in 2025, 2024, and 2023, respectively.
LIFO Inventory. In 2025, 2024, and 2023, net income included gains of $ 0.3 billion, $ 0.2 billion, and $ 0.4 billion, 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 $ 7 billion and $ 10 billion at December 31, 2025 and 2024, respectively.
Crude oil, products, and merchandise as of year-end 2025 and 2024 consist of the following:
(millions of dollars)
Dec 31, 2025
Dec 31, 2024
Crude oil
Petroleum products
Chemical products (1)
Gas/other
Total
(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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Government Assistance. ASC 832 "Government Assistance" requires disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. During 2023 to 2025, certain governments provided payments which, individually and in aggregate, were immaterial to the Corporation's consolidated financial statements. The terms and conditions of these programs, including their duration, vary by country. 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 Corporation records these allowances at a nominal amount, generally in "Inventories - Crude oil, products and merchandise" on the Consolidated Balance Sheet.
Note 15. Income and Other Taxes
(millions of dollars)
Non-U.S.
Total
Non-U.S.
Total
Non-U.S.
Total
Income tax expense (benefit)
Federal and non-U.S.
Current
Deferred - net
U.S. tax on non-U.S. operations
Total federal and non-U.S.
State
Total income tax expense (benefit)
All other taxes and duties
Other taxes and duties
Included in production and manufacturing expenses
Included in SG&A expenses
Total other taxes and duties
Total
The above provisions for deferred income taxes include net expenses of $ 64 million in 2025, net benefits of $ 28 million in 2024, and net expenses of $ 24 million in 2023, related to changes in tax laws and rates .
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company adopted the Financial Accounting Standards Board’s ASU No. 2023‑09, Improvements to Income Tax Disclosures, on a prospective basis for its 2025 annual reporting, in accordance with the transition provisions.
The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2025 is as follows:
(millions of dollars)
Income (loss) before income taxes
United States
Non-U.S.
Total
U.S. federal statutory theoretical tax
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax
United Arab Emirates rate differential
Qatar
Effect of equity method of accounting
Other
All other countries
State taxes, net of federal tax benefit
Other
Total income tax expense (credit)
Income tax expense (credit)
ExxonMobil share of equity company income taxes
Total income tax expense (credit)
Net income (loss) including noncontrolling interests
Total income (loss) before taxes
Effective income tax rate
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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, and 2023 is as follows:
(millions of dollars)
Income (loss) before income taxes
United States
Non-U.S.
Total
Theoretical tax
Effect of equity method of accounting
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax
State taxes, net of federal tax benefit
Other
Total income tax expense (credit)
Income tax expense (credit)
ExxonMobil share of equity company income taxes
Total income tax expense (credit)
Net income (loss) including noncontrolling interests
Total income (loss) before taxes
Effective income tax rate
Income taxes paid for 2025 U.S. and non-U.S. are shown in the table below:
(millions of dollars)
Income taxes paid
U.S. Federal
U.S. State
Canada
Guyana
United Arab Emirates
All Other Countries
Non-U.S.
Total income taxes paid
Cash income taxes paid for 2024 and 2023 were $ 13,293 million and $ 15,473 million respectively.
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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)
Property, plant, and equipment
Other liabilities
Total deferred tax liabilities
Pension and other postretirement benefits
Asset retirement obligations
Tax loss carryforwards
Other assets
Total deferred tax assets
Asset valuation allowances
Net deferred tax liabilities
In 2025, asset valuation allowances of $ 2,649 million increased by $ 133 million and included net provisions of $ 39 million and foreign currency and other effects of $ 172 million.
Balance sheet classification
(millions of dollars)
Other assets, including intangibles, net
Deferred income tax liabilities
Net deferred tax liabilities
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, 2025, 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.
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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)
Balance at January 1
Additions based on current year's tax positions
Additions for prior years' tax positions
Reductions for prior years' tax positions
Reductions due to lapse of the statute of limitations
Settlements with tax authorities
Foreign exchange effects/other
Balance at December 31
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 2025, 2024, and 2023 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. 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.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Country of Operation
Open Tax Years
Canada
Kazakhstan
Papua New Guinea
Qatar
United Arab Emirates
United States
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.
For 2025, 2024, and 2023 the Corporation's net interest expense on income tax reserves was $ 99 million, $ 142 million, and $ 60 million, respectively. The related interest payable balances were $ 365 million and $ 275 million at December 31, 2025 and 2024, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. 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)
Balance beginning at January 1
Additions pending the determination of proved reserves
Charged to expense
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
Divestments/Other
Ending balance at December 31
Ending balance attributed to equity companies included above
Period-end capitalized suspended exploratory well costs
(millions of dollars)
Capitalized for a period of one year or less
Capitalized for a period of between one and five years
Capitalized for a period of between five and ten years
Capitalized for a period of greater than ten years
Capitalized for a period greater than one year - subtotal
Total
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.
Number of projects that only have exploratory well costs capitalized for a period of one year or less
Number of projects that have exploratory well costs capitalized for a period greater than one year
Total
Of the 25 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2025, 10 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 15 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 17. 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 2025, the Corporation completed the sale of the Product Solutions affiliates in France. The sale included cash proceeds as well as cash from a financing arrangement which was assumed by the buyer upon closing.
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 20 .
In 2023, the Corporation completed the acquisition of Denbury Inc. (Denbury) through the issuance of 46 million shares of ExxonMobil Corporation common stock having a fair value of $ 4.8 billion on the acquisition date. Additional information is provided in Note 20 .
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 2025, 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 and Argentina and retail fuels assets in Singapore. For 2024, the number 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. These net (gain)/loss amounts are reported in "Other income" on the Consolidated Statement of Income.
(millions of dollars)
Cash interest paid
Included in cash flows from operating activities
Capitalized, included in cash flows from investing activities
Total cash interest paid
Note 18. 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 2025, remaining shares available for award under the 2003 Incentive Program were 41 million.
Restricted Stock and Restricted Stock Units. Awards of restricted (nonvested) common stock units granted under the 2003 Incentive Program totaled 9,852 thousand, 10,393 thousand, and 9,701 thousand in 2025, 2024, and 2023, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2025, remaining shares available for awards under the Pioneer LTIP were 9,426 thousand. The program is set to expire in May 2026.
The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2025.
Restricted stock and units outstanding
Shares
(thousands)
Weighted-Average
Grant-Date
Fair Value per Share
(dollars)
Issued and outstanding at January 1
Awards issued in 2025
Vested
Forfeited
Issued and outstanding at December 31
Impacts of Pioneer awards incorporated in the totals above include 49 thousand awards issued in 2025, ( 189 ) thousand vested and ( 65 ) thousand forfeited.
Value of restricted stock units
Grant price (dollars)
Value at date of grant:
(millions of dollars)
Units settled in stock
Units settled in cash
Total value
As of December 31, 2025, there was $ 2.7 billion 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 $ 1.0 billion, $ 0.8 billion, and $ 0.6 billion for 2025, 2024, and 2023, respectively. The income tax benefit recognized in income related to this compensation expense was $ 0.1 billion, $ 0.1 billion, and $ 0.1 billion for the same periods, respectively. The fair value of shares and units vested in 2025, 2024, and 2023 was $ 1.0 billion, $ 1.0 billion, and $ 0.9 billion, respectively. Cash payments of $ 0.1 billion, $ 0.1 billion, and $ 0.1 billion for vested restricted stock units settled in cash were made in 2025, 2024, and 2023, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 19. Divestment Activities
In 2025, the Corporation realized proceeds of approximately $ 3.2 billion and recognized net after-tax earnings of approximately $ 1.1 billion from its divestment activities. This included the sale of the Singapore retail fuels business, Mobil Argentina S.A., Product Solutions affiliates in France, certain conventional and unconventional assets in the United States, and other smaller divestments.
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.
Note 20. Mergers and Acquisitions
Pioneer Natural Resources Company
On May 3, 2024, the Corporation acquired Pioneer Natural Resources Company (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 fair values of the assets acquired and liabilities assumed.
(billions of dollars)
Pioneer
Current assets (1)
Other non-current assets
Property, plant, & equipment (2)
Total identifiable assets acquired
Current liabilities (1)
Long-term debt (3)
Deferred income tax liabilities (4)
Other non-current liabilities
Total liabilities assumed
Net identifiable assets acquired
Goodwill (5)
Net assets
(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 preliminarily 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.
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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)
1.125 % Senior Notes due January 2026
5.100 % Senior Notes due March 2026
7.200 % Senior Notes due January 2028
4.125 % Senior Notes due February 2028
1.900 % Senior Notes due August 2030
2.150 % Senior Notes due January 2031
(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
Net income (loss) attributable to ExxonMobil
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,
Sales and other operating revenues
Net income (loss) attributable to ExxonMobil
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.
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. Substantially all of the purchase price was allocated to property, plant, and equipment and long-term liabilities. 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.
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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 $1.9 billion in 2025, $1.4 billion in 2024 and $(0.5) billion in 2023. 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
Consolidated Subsidiaries
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated subsidiaries
Equity Companies
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
Total results of operations
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Results of Operations
(millions of dollars)
United
States
Canada/
Other
Americas
Europe
Africa
Asia
Australia/
Oceania
Total
Consolidated Subsidiaries
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated subsidiaries
Equity Companies
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
Total results of operations
Consolidated Subsidiaries
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated subsidiaries
Equity Companies
Sales to third parties
Transfers
Revenue
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
Total results of operations
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Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $9.1 billion less at year-end 2025 and $9.6 billion less at year-end 2024 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, 2025
Consolidated Subsidiaries
Property (acreage) costs
– Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Equity Companies
Property (acreage) costs
– Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for equity companies
As of December 31, 2024
Consolidated Subsidiaries
Property (acreage) costs
– Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Equity Companies
Property (acreage) costs
– Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for equity companies
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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 2025 were $27.8 billion, down $77.3 billion from 2024, due primarily to the absence of the Pioneer acquisition and partly offset by higher development costs. In 2024, costs were $105.1 billion, up $84.1 billion from 2023, due primarily to the Pioneer acquisition and higher development costs. Total equity company costs incurred in 2025 were $0.8 billion, down $0.3 billion from 2024, 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 2025
Consolidated Subsidiaries
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
During 2024
Consolidated Subsidiaries
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
During 2023
Consolidated Subsidiaries
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs
– Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
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Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2023, 2024, and 2025.
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 2025 that were associated with production sharing contract arrangements was 12 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 2025 year-end proved reserves and 2024 year-end proved reserves include worldwide production of 1.8 billion oil-equivalent barrels (GOEB), asset sales of 0.1 GOEB primarily in the United States, and downward revisions of 0.9 GOEB attributed primarily to the United States. Additions to proved reserves include 2.1 GOEB from extensions and discoveries primary in the United States and Guyana and 0.1 GOEB related to United States acquisitions.
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.
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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, 2023
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2023
Attributable to noncontrolling interests
Proportional interest in proved reserves of equity companies
January 1, 2023
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2023
Total liquids proved reserves at December 31, 2023
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2024
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2024
Attributable to noncontrolling interests
Proportional interest in proved reserves of equity companies
January 1, 2024
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2024
Total liquids proved reserves at December 31, 2024
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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, 2025
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2025
Attributable to noncontrolling interests
Proportional interest in proved reserves of equity companies
January 1, 2025
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2025
Total liquids proved reserves at December 31, 2025
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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, 2023
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at December 31, 2023
As of December 31, 2024
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at December 31, 2024
As of December 31, 2025
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at December 31, 2025
(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 . Properties" in ExxonMobil’s 2025 Form 10-K.
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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, 2023
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2023
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2023
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2023
Total proved reserves at December 31, 2023
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2024
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2024
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2024
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2024
Total proved reserves at December 31, 2024
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
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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, 2025
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2025
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2025
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2025
Total proved reserves at December 31, 2025
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
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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, 2023
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total proved reserves at December 31, 2023
As of December 31, 2024
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total proved reserves at December 31, 2024
As of December 31, 2025
Proved developed reserves
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves
Consolidated subsidiaries
Equity companies
Total proved reserves at December 31, 2025
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
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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, 2023
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Equity Companies
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Total consolidated and equity interests in standardized measure of discounted future net cash flows
(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $3,055 million in 2023.
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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, 2024
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Equity Companies
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Total consolidated and equity interests in standardized measure of discounted future net cash flows
As of December 31, 2025
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Equity Companies
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Total consolidated and equity interests in standardized measure of discounted future net cash flows
(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $4,466 million in 2024 and $3,132 million in 2025.
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Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests
(millions of dollars)
Consolidated Subsidiaries
Share of Equity Method Investees
Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2022
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs
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
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
Discounted future net cash flows as of December 31, 2023
Consolidated and Equity Interests
(millions of dollars)
Consolidated Subsidiaries
Share of Equity Method Investees
Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2023
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs
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
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
Discounted future net cash flows as of December 31, 2024
Consolidated and Equity Interests
(millions of dollars)
Consolidated Subsidiaries
Share of Equity Method Investees
Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2024
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs
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
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
Discounted future net cash flows as of December 31, 2025
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INDEX TO EXHIBITS
Exhibit
Description
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).
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).
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 November 25, 2025, as amended effective January 1, 2026.*
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).*
Code of Ethics and Business Conduct.
Insider Trading Policy (incorporated by reference to Exhibit 19 to the Registrant’s Annual Report on Form 10-K for 2024).
Subsidiaries of the registrant.
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Financial Officer.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Financial Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.
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).
Interactive data files (formatted as Inline XBRL).
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.
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
/s/ DARREN W. WOODS
Dated February 18, 2026
Darren W. Woods, Chairman of the Board
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Matthew R. Rasmussen, Wendi J. Powell, 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 18, 2026.
Principal Executive Officer
Directors
/s/ DARREN W. WOODS
/s/ MICHAEL J. ANGELAKIS
/s/ JOSEPH L. HOOLEY
Darren W. Woods, Chairman of the Board
Michael J. Angelakis
Joseph L. Hooley
/s/ ANGELA F. BRALY
/s/ STEVEN A. KANDARIAN
Principal Financial Officer
Angela F. Braly
Steven A. Kandarian
/s/ NEIL A. HANSEN
/s/ MARIA S. DREYFUS
/s/ ALEXANDER A. KARSNER
Neil A. Hansen, Senior Vice President and Chief Financial Officer
Maria S. Dreyfus
Alexander A. Karsner
/s/ GREG C. GARLAND
/s/ LAWRENCE W. KELLNER
Principal Accounting Officer
Greg C. Garland
Lawrence W. Kellner
/s/ LEN M. FOX
/s/ JOHN D. HARRIS II
/s/ DINA POWELL MCCORMICK
Len M. Fox, Vice President,
Controller and Tax
John D. Harris II
Dina Powell McCormick
/s/ KAISA H. HIETALA
/s/ JEFFREY W. UBBEN
Kaisa H. Hietala
Jeffrey W. Ubben
