Document: SEC Filing

Company: Exxon Mobil Corp.
Ticker: XOM
CIK: 34088
Form Type: 10-K
Filing Date: 2026-02-18
Accession Number: 0000034088-26-000045
Source: 10-K_2026-02-18_0000034088-26-000045.txt

---

2025

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM

10-K

☑

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31
, 2025

or
☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
              
to
              
Commission File Number
1-2256

Exxon Mobil Corporation

(Exact name of registrant as specified in its charter)
New Jersey 13-5409005
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)

22777 Springwoods Village Parkway
,

Spring
,

Texas

77389-1425

(Address of principal executive offices) (Zip Code)
(
972
)

940-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Trading Symbol Name of Each Exchange on Which Registered
Common Stock, without par value XOM New York Stock Exchange
0.524% Notes due 2028 XOM28 New York Stock Exchange
0.835% Notes due 2032 XOM32 New York Stock Exchange
1.408% Notes due 2039 XOM39A New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐
No
☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
 ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes
☐
No ☑
The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $107.80 on the New York Stock Exchange composite tape, was in excess of $
460
billion.
Class Outstanding as of January 31, 2026
Common stock, without par value 4,166,763,453

Documents Incorporated by Reference:

Proxy Statement for the 2026 Annual Meeting of Shareholders (Part III)

EXXON MOBIL CORPORATION
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2025
TABLE OF CONTENTS
PART I
Item 1. Business 1
Item 1A. Risk Factors 2
Item 1B. Unresolved Staff Comments 8
Item 1C. Cybersecurity 8
Item 2. Properties 9
Item 3. Legal Proceedings 22
Item 4. Mine Safety Disclosures 22
Information about our Executive Officers 23
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 24
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 24
Item 8. Financial Statements and Supplementary Data 25
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 25
Item 9A. Controls and Procedures 25
Item 9B. Other Information 26
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 26
PART III
Item 10. Directors, Executive Officers and Corporate Governance 26
Item 11. Executive Compensation 26
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 27
Item 13. Certain Relationships and Related Transactions, and Director Independence 27
Item 14. Principal Account ant Fees and Services 27
PART IV
Item 15. Exhibit and Financial Statement Schedules 27
Item 16. Form 10-K Summary 27
Financial Section 28
Index to Exhibits 128
Signatures 129

Table of Contents Financial Table of Contents

PART I
ITEM 1. BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Our 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. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation's divisions and affiliates have many names, including
ExxonMobil
,
Exxon
,
Esso, Mobil
or
XTO
. For convenience and simplicity, in this report the terms
ExxonMobil, Exxon, Esso, Mobil, and XTO
, as well as terms like
Corporation
,
Company
,
our
,
we,
and
its
, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.
The energy and petrochemical industries are highly competitive, both within the industries and also with other industries in supplying the energy, fuel, and chemical needs of industrial and individual consumers. Certain industry participants, including ExxonMobil, are expanding the scope of investments in lower-emission energy and emission-reduction services and technologies. The Corporation competes with other firms in the sale or purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.
Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Management's Discussion and Analysis of Financial Condition and Results of Operations:
Business Results
” and
Note 3
. Information on oil and gas reserves is contained in the
“Oil and Gas Reserves”
part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report.
ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our businesses. ExxonMobil held over 8 thousand active patents worldwide at the end of 2025. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise, or concession.
ExxonMobil operates in a highly complex, competitive, and changing global energy business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the Corporation's philosophy on talent development.
Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of our business across the business cycle. Our career-oriented approach to talent development results in strong retention and an average length of service of about 30 years for our career employees. Compensation, benefits, and workplace programs support the Corporation's talent management approach, and are designed to attract and retain employees for a career through compensation that is market competitive, long-term oriented, and highly differentiated by individual performance.
With over 59 percent of our global employees from outside the U.S. and more than 160 nationalities represented across the Company, we encourage and respect diversity of thought, ideas, and perspective from our workforce. We are focused on building an engaged, global workforce; grounded in meritocracy, we strive to have every employee reach their potential over a long-term career by providing unrivaled opportunities for personal and professional growth through impactful work meeting society's essential needs.
The number of regular employees was 58 thousand, 61 thousand, and 62 thousand at years ended 2025, 2024, and 2023, respectively. 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.
As discussed in
Item 1
A
in this report, compliance with existing and potential future government regulations, including taxes, environmental regulations, and other government regulations and policies that directly or indirectly affect the production and sale of our products, may have material effects on the capital expenditures, earnings, and competitive position of ExxonMobil. For additional information on the Corporation's worldwide environmental expenditures, see "Management's Discussion and Analysis of Financial Condition and Results of Operations:
Environmental Matters
" in the Financial Section of this report.
Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments, and risks attendant to foreign operations may be found in
Item 1A
and
Item 2
in this report.
1
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ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission (SEC). Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines, Code of Ethics and Business Conduct, and additional policies as well as the charters of the audit, compensation, and other committees of the Board of Directors. Information on our website is not incorporated into this report.
The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.
ITEM 1A. RISK FACTORS

ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses and the pursuit of lower-emission and other new business opportunities. Many of these risk factors are not within the Company’s control and could adversely affect our business, our financial and operating results, or our financial condition. These risk factors include:
Supply and Demand
The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas, and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical, and product prices and margins in turn depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity or product. Any material decline in oil or natural gas prices could have a material adverse effect on the Company’s operations, results, financial condition, and proved reserves, especially in the Upstream segment. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on the Company’s operations and results, especially in the Energy Products, Chemical Products, and Specialty Products segments. Our 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 also depends on the growth and development of markets for those products and services, including implementation of supportive and stable government policies and developments in existing and new technology to enable those products and services to be provided on a cost-effective basis at commercial scale. See “Climate Change and Energy Transition” in this Item 1A.
Economic conditions.
The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of economic downturns, recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates or living standards, periods of civil unrest or armed hostilities, escalating geopolitical volatility, government regulation or austerity programs, national or regional trade tariffs, trade sanctions or trade controls, international monetary and currency exchange rate fluctuations, decoupling of economies, disruption, realignment, or breaking of current or historical trade or military alliances or global trade or supply chain networks, changes in international trade patterns or shipping routes, or a broader breakdown in global trade, security or public health, can also impact the supply and demand for energy and petrochemicals. Sovereign debt downgrades, defaults, extended government shutdowns, inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, market bubbles and corrections, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, de-dollarization in global trade or the growth or use of alternative common currencies, and other events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners, suppliers, and customers to fulfill their commitments to ExxonMobil. Our future business, including earnings, cash flows, and financing needs, may also be affected by the occurrence, severity, pace, and rate of recovery of future public health epidemics or pandemics or other natural or human events beyond our control; the responsive actions taken by governments and others; and the resulting effects on regional and global markets and economies.
Other demand-related factors.
Other factors that may affect the demand for oil, gas, petrochemicals or our other products, and therefore our results, include technological improvements in energy efficiency; seasonal weather patterns; increased competitiveness of, or government policy support for, alternative energy sources or potential substitutes for our products; changes in technology that alter fuel choices, such as technological advances in energy storage or other critical areas that make wind, solar, nuclear, or other alternatives more competitive for power generation; government actions to increase strategic reserves to enhance energy security; increased demand for artificial intelligence (AI), including the construction and expansion of AI data centers; changes in customer or consumer preferences for our products, including consumer demand for alternative-fueled or electric transportation or alternatives to plastic products; and broad-based changes in personal income levels. See also “Climate Change and Energy Transition” below.
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Other supply-related factors.
Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new or previously inaccessible oil and gas supply sources and technologies to enhance recovery from existing sources tends to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as the level of, and adherence by, participating countries to production quotas established by OPEC or OPEC+ and other agreements among sovereigns; government policies, including actions intended to reduce greenhouse gas emissions, that restrict oil and gas production or increase associated production, reporting or compliance costs; collective actions by non-governmental organizations and financial institutions to withhold funding or support from oil and gas producers; the occurrence of wars or hostile actions, including disruption of land or sea transportation routes; natural disasters; disruptions in competitors’ operations; and logistics constraints or unexpected unavailability of distribution channels that may disrupt supplies. There also may be new or emerging factors that could increase global oil, gas, and petrochemical supply levels in the short or long term, such as government policies and actions intended to boost or expand development of domestic or foreign oil and gas reserves or accelerate the pace of production reaching markets, including access to previously unavailable, sanctioned, or protected oil and gas resources or the availability or opening of new shipping routes. Dynamic and unpredictable world events may lead to new oil and gas opportunities becoming available or current opportunities becoming less available or unavailable, and such events may adversely affect our business and results. Technological change can also alter the relative costs for competitors to find, produce and refine oil and gas, and to manufacture petrochemicals.
Other market factors.
ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest rates, inflation, currency exchange rates, changes in usage of the U.S. dollar in global trade, and other local or regional market conditions. In addition to direct potential impacts on our costs and revenues, market factors such as rates of inflation may indirectly impact our results to the extent such factors reduce general rates of economic growth and therefore energy demand, as discussed under “Economic conditions.” Market factors may also result in losses from commodity derivatives and other instruments we use to hedge price exposures or for commodity and treasury trading activities. Additional information regarding the potential future impact of market factors on our businesses is included or incorporated by reference under
Item 7A
in this report.
Government and Political Factors
ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our businesses or operations.
Access limitations.
A number of countries limit access to their oil and gas resources, including by restricting leasing, licensing, or permitting activities directly or indirectly through the influence on these processes by well-funded local or international groups opposing the development of these resources. They also may place resources off-limits from development altogether. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy, security, and climate policies. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices or when national governments may have less need for outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin, and such restrictions may increase during periods of escalating geopolitical or trade tensions.
Restrictions on doing business.
ExxonMobil is subject to laws and sanctions imposed by the United States and by other jurisdictions where we do business that may prohibit ExxonMobil or its affiliates from doing business in certain countries or with certain counterparties or restrict or impede the kind of business that may be conducted, including acquiring and divesting certain assets or importing or exporting certain materials or products. Such restrictions may provide a competitive advantage to competitors who may not be subject to comparable restrictions.
Lack of legal certainty.
Some countries in which we do, or seek to do, business lack well-developed legal systems, lack political or governmental stability, may be subject to regime changes, have not yet adopted clear legal frameworks, may be unable to maintain clear regulatory frameworks in the face of pressure on their systems from well-funded local or international groups opposing development of their resources, or may have evolving and unharmonized standards that vary or conflict across jurisdictions. Lack of legal certainty exposes us to increased risk of adverse or unpredictable actions by government officials, may reduce our ability to comply timely or cost-effectively with evolving standards or requirements, and also makes it more difficult for us to enforce our contracts. In some cases, these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.
Regulatory and litigation risks.
Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law or interpretation or enforcement of settled law, including changes that result from concerted efforts to increase our legal exposure by groups opposed to the products we provide or international treaties and accords or changes by local jurisdictions encroaching on national regulatory frameworks or global issues or changes resulting from imposition of extraterritorial laws and regulations, and changes in government policy or priorities that could adversely affect our results, such as:
•
increases or changes in taxes, duties, or government royalty rates, including retroactive claims, punitive taxes on oil, gas and petrochemical operations, windfall profit taxes, or global minimum taxes;
•
price controls;
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•
changes in environmental, advertising, insurance or other regulations or laws that penalize us for past or current production of legal and/or permitted products and operations, increase our cost of operation or compliance or reduce or delay available business opportunities, including changes in laws or regulations affecting offshore drilling operations, standards to complete decommissioning, standards for water use or availability, production of our products, emissions, hydraulic fracturing, or production or use of new or recycled plastics, as well as laws and regulations affecting trading, carbon capture and storage, hydrogen and ammonia, lower-emission fuels, Proxxima
TM
resin systems, carbon materials, low-carbon data centers, or lithium;
•
actions by governments, policy-makers, regulators, or other actors to delay or deny necessary licenses and permits, restrict the availability of oil and gas leases, investment opportunities, or the transportation or export of our products, pause, reduce, or retract government incentives for emissions reductions, disrupt or impact reliability as a result of policy decisions on types and pricing of energy available, or otherwise require changes in the Company's business or strategy that could result in reduced returns;
•
regulatory interpretations that exclude or disfavor our products under government policies or programs intended to support new or developing markets or technologies, or that otherwise are not technology-neutral;
•
adoption of regulations mandating efficiency standards, emission standards, procurement standards, the use of alternative fuels, or uncompetitive fuel components;
•
use of regulatory or legal standards by any nation or supranational body as a foreign policy tool;
•
unstable policies or shifting regulations impacting new or emerging markets;
•
adoption of disclosure regulations that could create competitive disadvantages, require us to incur disproportionate costs, increase legal risk due to a need to rely on uncertain estimates or extrapolations (such as emissions of third parties) and lack of uniform standards across jurisdictions, require us to make statements we disagree with, or require us to disclose competitively sensitive commercial information or to violate the non-disclosure laws of other countries; and
•
government actions to cancel contracts, redenominate the official currency, renounce or default on obligations, impose unwarranted penalties, renegotiate terms unilaterally, expropriate assets, or compel a change in production plans.
Legal remedies available to compensate us for expropriation or other takings may be inadequate.
We also may be adversely affected by the outcome of litigation, including class actions or arbitrations, especially in countries such as the United States that permit large and unpredictable punitive and non-economic damage awards. Other jurisdictions adopting similar models to impose liability schemes on our products or operations may present similar risks. We also may be adversely affected by government investigations or enforcement proceedings alleging non-compliance with applicable laws or regulations, or by state and local government actors as well as private plaintiffs acting in parallel that attempt to use the legal system to promote public policy agendas (including seeking to reduce the production and sale of hydrocarbon products through litigation targeting the Company or other industry participants), gain political notoriety, or obtain monetary awards from the Company. The continued adoption of similar legal practices in the European Union or elsewhere would broaden this risk.
Security concerns.
Successful operation of particular facilities or projects may be disrupted by civil unrest, military conflict, acts of sabotage, piracy, terrorism, cybersecurity attacks, the application of national security laws or policies that result in restricting our ability to do business in a particular jurisdiction or region, strikes or protests, and other local, national, regional, or global security concerns. Such concerns may be directed specifically at our Company, our industry, or as part of broader movements and may require us to incur greater costs for security or to shut down operations for a period of time.
4
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Climate Change and Energy Transition
Net-zero scenarios.
Driven by concern over the risks of climate change, a number of countries have adopted, or are considering the adoption of, broad-reaching regulatory frameworks seeking to report on or reduce greenhouse gas emissions, including emissions from the production and use of oil and gas and their products, as well as increase the use of, or support for, different emission-reduction technologies. These actions are being taken both independently by national and regional governments and within the framework of United Nations Conference of the Parties summits under which many countries of the world have endorsed objectives to reduce the atmospheric concentration of carbon dioxide (CO2) over the coming decades, with an ambition ultimately to achieve “net zero.” Net zero means that emissions of greenhouse gases from human activities would be balanced by actions that remove such gases from the atmosphere. Expectations for transition of the world’s energy system to lower-emission sources, and ultimately net-zero, derive from hypothetical scenarios that reflect many assumptions about the future, including supportive policy and technology advancements, and reflect substantial uncertainties. The Company seeks opportunities to play a leading role in the energy transition, including the Company’s announced ambition ultimately to achieve net zero with respect to Scope 1 and 2 emissions from our operated assets with continued technology development and government policy support, which carries risks that the transition, including underlying technologies, government policies, and markets as discussed in more detail below, will not be available or develop at the pace or in the manner expected by current net-zero scenarios. Without supportive policies and the innovations they drive, net zero will remain out of reach – for society and for ExxonMobil. Society’s progress continues to lag in these areas. The success of our strategy in a lower-emissions future will also depend on our ability to recognize key signposts of changes in the global energy system on a timely basis, and our corresponding ability to direct investment to the technologies and businesses, at the appropriate stage of development, to best capitalize on our competitive strengths.
Greenhouse gas restrictions.
Government actions intended to reduce greenhouse gas emissions include adoption of cap and trade regimes, carbon taxes, carbon accounting, carbon-based import duties or other trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, restrictions on sales of gasoline-only vehicles, mandates for disclosure of plans to reduce emissions or reduce the use or production of certain products, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support certain technologies for transitioning to lower-emission energy sources. Political actors, non-governmental organizations, and their agents also increasingly seek to collectively advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. These actions include delaying or blocking needed infrastructure, utilizing shareholder governance mechanisms against companies or their shareholders or financial institutions in an effort to deter investment in oil and gas activities, and taking other actions intended to promote changes in business strategy for oil and gas companies. Depending on how policies are formulated and applied, such policies could negatively affect our investment returns, make our hydrocarbon-based products more expensive or less competitive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon alternatives. Current, pending, and potential greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering emissions and complying with increased or mandatory disclosure or due diligence requirements and government-mandated energy transition plans.
Technology and lower-emission solutions.
Achieving societal ambitions to reduce greenhouse gas emissions and ultimately achieve net zero will require new technologies and added infrastructure to reduce the cost and increase the scalability of solutions to reduce emissions, as well as technologies such as carbon capture and storage (CCS). CCS technologies, focused initially on capturing and sequestering CO2 emissions from high-carbon intensity industrial activities, can assist in meeting society’s objective to mitigate atmospheric greenhouse gas levels while also helping to ensure the availability of the reliable and affordable energy the world requires. ExxonMobil has established a Low Carbon Solutions (LCS) business unit and is continuing efforts in our existing businesses to advance the development and deployment of these technologies and projects, including CCS, hydrogen and ammonia, lower-emission fuels, Proxxima
TM
resin systems, advanced energy-saving materials, low-carbon data centers, lithium, and other technologies. The Company’s efforts include both in-house research and development as well as collaborative efforts with leading universities and with commercial partners involved in new energy technologies. Our future results and ability to grow our business, help others meet their emission-reduction goals, and succeed in a lower-emissions future will depend in part on the success of these research and collaboration efforts and on our ability to adapt and apply the strengths of our current business model to providing the energy products of the future in a cost-competitive manner.
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Policy and market development.
The scale of the world’s energy system means that, in addition to developments in technology as discussed above, meeting society's needs for energy and reducing emissions will require appropriate support from governments and private participants throughout the global economy. Our ability to develop and deploy CCS and other new energy technologies at commercial scale, and the growth and future returns of LCS and other emerging businesses in which we invest, will depend in part on the development of stable and supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained could adversely impact or delay these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without a commensurate reduction in demand may have unpredictable adverse effects, including increased commodity price volatility; periods of significantly higher commodity prices and resulting inflationary pressures; and local or regional energy shortages. Such effects in turn may depress economic growth or lead to rapid or conflicting shifts in policy by different actors, with resulting adverse effects on our businesses. In addition, the existence of supportive policies in any jurisdiction is not a guarantee that those policies will continue in the future. See also the discussion of “Supply and Demand,” “Government and Political Factors,” and “Operational and Other Factors” in this Item 1A.
Operational and Other Factors
In addition to external economic and political factors, our future business results also depend on our ability to successfully manage those factors that are, at least in part, within our control, including our investment into existing and new businesses. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.
Exploration and development program.
Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources online as scheduled and within budget.
Project and portfolio management.
The long-term success of ExxonMobil’s Upstream and Product Solutions businesses, as well as the future success of LCS and other emerging investments, depends on complex, long-term, capital-intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; protect and enforce our contractual and legal rights, including with our joint venture partners, host governments, and others; model and optimize reservoir performance and production reliability; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; qualify for certain incentives available under supportive government policies for emerging markets and technologies; manage changes in operating conditions and costs, including costs of third-party equipment or services such as drilling rigs and shipping, supply chain disruptions, and inflationary cost pressures; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project start-up, incur or escalate costs, or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role. In addition to the effective management of individual projects, ExxonMobil’s success, including our ability to mitigate risk and provide attractive returns to shareholders, depends on our ability to successfully manage our overall portfolio, including diversification among types and locations of our projects, products produced, and strategies to acquire or divest assets. We may not be able to acquire or divest assets at a price or on the timeline we contemplate in our strategies. Additionally, we may retain certain liabilities following a divestment and could be held liable for past use or for different liabilities than anticipated, including reversion of decommissioning or other liabilities upon bankruptcy or other default of successors in title.
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.
Operational efficiency.
An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses, improve production yields on an ongoing basis, and successfully integrate and achieve the anticipated synergies of acquisitions. This requires continuous management focus, including technology integration and improvements, cost control, productivity enhancements, harmonizing functions, policies, procedures and processes, regular reappraisal of our asset portfolio, and the recruitment, development, and retention of high caliber employees.
Research and development and technological change.
To maintain our competitive position, especially in light of the technological nature of our businesses, the dynamic and rapidly evolving technological landscape, and the need for continuous efficiency improvement, ExxonMobil’s technology, research, and development organizations must be successful and able to adapt to a changing market, regulatory, and policy environment, both nationally and internationally, including continuous improvement in the efficiency of hydraulic fracturing technology and developing technologies to help reduce greenhouse gas emissions. To remain competitive, we must also continuously adapt and capture the benefits of new and emerging technologies, such as AI, including successfully applying advances in the ability to process and integrate large amounts of data to our businesses and decision-making processes.
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Safety, business controls, and risk management.
Our results depend on management’s ability to minimize the inherent risks of oil, gas, and petrochemical operations, as well as potential risks related to new energy and other technologies, to effectively control our business activities, including trading, and to minimize the potential for human error. We apply rigorous management systems and continuous focus on workplace safety, spills avoidance, and other adverse environmental events. For example, we work to minimize spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are implementing cost-effective new technologies and adopting new operating practices to reduce emissions, not only in response to government requirements but also to address community priorities. We employ a robust and actively evolving enterprise risk management system to identify and manage risk across our businesses. We also maintain a disciplined framework of internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if we do not timely identify and mitigate applicable risks, or if our management systems and controls do not function as intended.
Cybersecurity.
ExxonMobil is regularly subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors. See
Item 1C
in this report for information on ExxonMobil’s program for managing cybersecurity risks. If the measures we are taking to protect against cybersecurity disruptions prove to be insufficient or if our proprietary data is otherwise not protected, ExxonMobil, as well as our customers, employees, or third parties, could be adversely affected. We have limited ability to influence third parties, including our partners, suppliers, and service providers (including providers of cloud-hosting services for our data or applications), to implement strong cybersecurity controls and are exposed to potential harm from cybersecurity events that may affect their operations. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation, or reputational harm.
Preparedness.
Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our facilities are designed, engineered, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of uncertainties, including those associated with wave, wind, and current intensity, marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rainfall events, and earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design cover the engineering uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our robust facility engineering, our rigorous disaster preparedness and response, and business continuity planning.
Insurance limitations.
The ability of the Corporation to insure against many of the risks it faces as described in this Item 1A is limited by the availability and cost of coverage, which may not be economic, as well as the capacity of the applicable insurance markets, which may not be sufficient.
Competition.
As noted in
Item 1
above, the energy and petrochemical industries are highly competitive. We face competition not only from other private firms, but also from state-owned companies that are increasingly competing for opportunities outside of their home countries and as partners with other private firms. In some cases, these state-owned companies may pursue opportunities in furtherance of strategic, national, or supranational objectives of their government owners, with less focus on financial returns than companies owned by private shareholders, such as ExxonMobil. Technology and expertise provided by industry service companies or AI may also enhance the competitiveness of firms that may not have the internal resources and capabilities of ExxonMobil or reduce the need for resource-owning countries to partner with private-sector oil and gas companies in order to monetize national resources. As described in more detail above, our hydrocarbon-based energy products are also subject to growing and, in many cases, government-supported competition from alternative energy sources. In addition, as we enter new markets in pursuit of lower-emission and other new business opportunities, we will need to compete effectively with established competitors in these markets, as well as with new market entrants seeking to capitalize on these opportunities, while successfully navigating changing market conditions or technologies.
Reputation.
Our reputation is an important corporate asset. Factors that could have a negative impact on our reputation include an operating incident or significant cybersecurity disruption; changes in consumer views concerning our products; changes in consumer media preferences from traditional mainstream media to decentralized and personalized media; a perception by investors or others that the Corporation is making insufficient progress with respect to our ambition to play a leading role in the energy transition, or that pursuit of this ambition may result in allocation of capital to investments with reduced returns; divergent and evolving societal views and investor pressures regarding a future energy transition; and other adverse events such as those described in this Item 1A. Negative impacts on our reputation could in turn make it more difficult for us to compete successfully for new opportunities, obtain necessary regulatory approvals, obtain financing, and attract talent, or they could reduce customer or consumer demand for our branded products. ExxonMobil’s reputation may also be harmed by events which negatively affect the image of our industry as a whole.
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Projections, estimates, and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 1C, 2, 5, 7, and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs, and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.
ITEM 1B. UNRESOLVED STAFF COMMENTS

None.
ITEM 1C. CYBERSECURITY

The Corporation recognizes the importance of cybersecurity in achieving its business objectives, safeguarding its assets, and managing its daily operations.
Accordingly, the Corporation integrates cybersecurity risks into its overall enterprise risk management system.

The Audit Committee oversees the Corporation’s risk management approach and structure, which includes an annual review of the Corporation’s cybersecurity program.

The Corporation’s cybersecurity program is managed by
the Corporation’s Vice President of Information Technology (IT), with support from cross-functional teams led by ExxonMobil IT and operational technology (OT) cybersecurity operations managers (collectively, Cybersecurity Operations Managers)
. The Cybersecurity Operations Managers are responsible for the day-to-day management and effective functioning of the cybersecurity program, including the prevention, detection, investigation, and response to cybersecurity threats and incidents.
The Cybersecurity Operations Managers collectively have many years of experience in cybersecurity operations.

IT management provides regular reports to the Corporation’s senior management throughout the year, and to the Audit Committee or the Board of Directors, as appropriate, in its annual cybersecurity review.

Such reports typically address, among other things, the Corporation’s cybersecurity strategy, initiatives, key security metrics, penetration testing and benchmarking learnings, and business response plans as well as the evolving cybersecurity threat landscape.

The Corporation’s cybersecurity program includes multi-layered technological capabilities designed to prevent and detect cybersecurity disruptions and leverages industry standard frameworks, including the National Institute of Standards and Technology Cybersecurity Framework. The cybersecurity program incorporates an incident response plan to engage cross-functionally across the Corporation and report cybersecurity incidents to appropriate levels of management, including senior management, and the Audit Committee or Board of Directors, based on potential impact. The Corporation conducts annual cybersecurity awareness training and routinely tests cybersecurity awareness and business preparedness for response and recovery, which are developed based on real-world threats.
In addition, the Corporation exchanges threat information with governmental and industry groups and proactively engages independent, third-party cybersecurity experts to test, evaluate, and recommend improvements on the effectiveness and resiliency of its cybersecurity program through penetration testing, breach assessments, regular cybersecurity incident drill testing, threat information sharing, and industry benchmarking.
The Corporation takes a risk-based approach with respect to its third-party service providers, tailoring processes according to the nature and sensitivity of the data or systems accessed by such third-party service providers, and performing additional risk screenings and procedures, as appropriate.
As of the date of this report, we have not identified any risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected, or are reasonably likely to materially affect the Corporation, including our business strategy, results of operations, or financial condition.
While the Corporation believes its cybersecurity program to be appropriate for managing constantly evolving cybersecurity risks, no program can fully protect against all possible adverse events. For additional information on these risks and potential consequences if the measures we are taking prove to be insufficient or if our proprietary data is otherwise not protected, see “
Item 1A
. Risk Factors: Operational and Other Factors -- Cybersecurity” in this report.

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ITEM 2. PROPERTIES

Information with regard to oil and gas producing activities follows:
1. Disclosure of Reserves
A. Summary of Oil and Gas Reserves at Year-End 2025    
The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. No major discovery or other favorable or adverse event has occurred since December 31, 2025, that would cause a significant change in the estimated proved reserves as of that date.
Proved Reserves Crude Oil Natural Gas Liquids Bitumen Synthetic Oil Natural Gas Oil-Equivalent Total All Products
(million bbls) (million bbls) (million bbls) (million bbls) (billion cubic ft) (million bbls)
Developed
Consolidated Subsidiaries
United States 1,552 1,075 — — 11,206 4,495
Canada/Other Americas (1) 586 1 2,230 288 356 3,164
Europe 3 — — — 338 60
Africa 185 — — — 111 204
Asia 1,871 44 — — 2,010 2,251
Australia/Oceania 32 6 — — 3,057 548
Total Consolidated 4,229 1,126 2,230 288 17,078 10,722
Equity Companies
United States 5 3 — — 48 16
Europe 2 — — — 207 36
Africa 7 — — — 775 136
Asia 462 134 — — 4,782 1,394
Total Equity Company 476 137 — — 5,812 1,582
Total Developed 4,705 1,263 2,230 288 22,890 12,304
Undeveloped
Consolidated Subsidiaries
United States 1,558 988 — — 5,581 3,476
Canada/Other Americas (1) 609 — 100 — 171 737
Europe — — — — — —
Africa 32 — — — 2 32
Asia 1,089 23 — — 189 1,143
Australia/Oceania 28 2 — — 2,653 472
Total Consolidated 3,316 1,013 100 — 8,596 5,860
Equity Companies
United States — — — — — —
Europe 3 — — — 56 12
Africa — — — — — —
Asia 163 161 — — 4,866 1,135
Total Equity Company 166 161 — — 4,922 1,147
Total Undeveloped 3,482 1,174 100 — 13,518 7,007
Total Proved Reserves 8,187 2,437 2,330 288 36,408 19,311
(1) Other Americas includes proved developed reserves of 486 million barrels of crude oil and 228 billion cubic feet of natural gas, as well as proved undeveloped reserves of 587 million barrels of crude oil and 162 billion cubic feet of natural gas.

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In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.
The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, the impact of fiscal and commercial terms, asset sales, weather events, price effects on production sharing contracts, changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment, international trade patterns and relations, and other factors described in
Item 1A
.
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of reservoir and well performance. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, and significant changes in crude oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.
B. Technologies Used in Establishing Proved Reserves Additions in 2025
Additions to ExxonMobil’s proved reserves in 2025 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 3‑D and 4‑D seismic data, calibrated with available well control information. The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of, and confidence in, the reserves estimates.
C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves
ExxonMobil has a dedicated Global Reserves and Resources group that provides technical oversight and is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude oil, natural gas liquids, bitumen, synthetic oil, and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The current Global Reserves and Resources Manager has more than 30 years of experience in reservoir engineering and reserves assessment, has a degree in Engineering, and serves on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers. The group is staffed with individuals that have an average of more than 15 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under SEC guidelines. This group includes individuals who hold degrees in either Engineering or Geology.
The Global Reserves and Resources group maintains a central database containing the official company reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long-standing approval guidelines. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized geoscience and engineering professionals within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval by the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Global Reserves and Resources group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.
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2. Proved Undeveloped Reserves
At year-end 2025, approximately 7.0 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 36 percent of the 19.3 GOEB reported in proved reserves. This compares to 7.4 GOEB of proved undeveloped reserves reported at the end of 2024. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 1.4 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to development activities in the United States, Guyana, Kazakhstan, the United Arab Emirates, Qatar, and Canada. In 2025, extensions and discoveries, primarily in the United States and Guyana, resulted in the addition of approximately 2.0 GOEB of proved undeveloped reserves. Also, the Corporation reclassified approximately 1.0 GOEB of proved undeveloped reserves which no longer met the SEC definition of proved reserves, primarily in the United States.
Overall, investments of $19.0 billion were made by the Corporation during 2025 to progress the development of reported proved undeveloped reserves, including $18.8 billion for oil and gas producing activities, along with additional investments for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities.
One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. 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. Proved undeveloped reserves in Australia and the United Arab Emirates have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these 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 policies, consumer preferences, the pace of co-venturer/government funding, changes in the amount and timing of capital investments, and significant changes in crude oil and natural gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, over 80 percent are contained in the aforementioned countries. In Australia, proved undeveloped reserves are associated with future compression for the Gorgon Jansz LNG project. In the United Arab Emirates, proved undeveloped reserves are associated with an approved development plan and continued drilling investment for the producing Upper Zakum field.
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3. Oil and Gas Production, Production Prices and Production Costs
A. Oil and Gas Production
The table below summarizes production by final product sold and by geographic area for the last three years.
(thousands of barrels daily) 2025 2024 2023
Crude Oil NGL Crude Oil NGL Crude Oil NGL
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States 1,005 514 862 383 556 238
Canada/Other Americas (1) 381 1 346 2 240 2
Europe 2 — 2 — 2 —
Africa 141 — 206 2 216 4
Asia 445 28 422 26 417 28
Australia/Oceania 18 7 20 10 24 12
Total Consolidated Subsidiaries 1,992 550 1,858 423 1,455 284
Equity Companies
United States 2 1 2 1 8 1
Europe 1 — 1 — 2 —
Africa 1 — 1 — 1 —
Asia 266 61 206 59 216 60
Total Equity Companies 270 62 210 60 227 61
Total crude oil and natural gas liquids production 2,262 612 2,068 483 1,682 345
Bitumen production
Consolidated Subsidiaries
Canada/Other Americas 385 374 355
Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas 68 62 67
Total liquids production 3,329 2,987 2,449
(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States 3,346 2,869 2,292
Canada/Other Americas (1) 27 101 96
Europe 228 252 266
Africa 2 45 35
Asia 968 907 915
Australia/Oceania 1,283 1,264 1,298
Total Consolidated Subsidiaries 5,854 5,438 4,902
Equity Companies
United States 18 18 19
Europe 71 100 148
Africa 112 107 90
Asia 2,386 2,415 2,575
Total Equity Companies 2,587 2,640 2,832
Total natural gas production available for sale 8,442 8,078 7,734
(thousands of oil-equivalent barrels daily)
Oil-equivalent production 4,736 4,333 3,738
(1) Other Americas includes crude oil production for 2025, 2024, and 2023 of 320 thousand, 285 thousand, and 178 thousand barrels daily, respectively; and natural gas production available for sale for 2025, 2024, and 2023 of 4 million, 76 million, and 67 million cubic feet daily, respectively.
Due to rounding, numbers presented may not add up precisely to the totals indicated.

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B. Production Prices and Production Costs
The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.
(dollars per unit) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total
2025
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 63.19 67.75 63.24 69.20 68.26 66.21 65.64
NGL, per barrel 20.87 28.98 47.44 — 30.83 47.75 21.71
Natural gas, per thousand cubic feet 1.07 1.21 11.91 1.90 2.27 7.72 3.15
Bitumen, per barrel — 46.13 — — — — 46.13
Synthetic oil, per barrel — 63.61 — — — — 63.61
Average production costs, per oil-equivalent barrel - total 11.07 15.63 30.70 20.38 5.15 5.60 11.29
Average production costs, per barrel - bitumen — 19.95 — — — — 19.95
Average production costs, per barrel - synthetic oil — 40.41 — — — — 40.41
Equity Companies
Average production prices
Crude oil, per barrel 62.71 — 63.64 66.94 61.75 — 61.79
NGL, per barrel 20.77 — — — 40.91 — 40.62
Natural gas, per thousand cubic feet 2.71 — 11.75 5.51 6.79 — 6.84
Average production costs, per oil-equivalent barrel - total 30.49 — 102.43 4.48 2.53 — 4.49
Total
Average production prices
Crude oil, per barrel 63.19 67.75 63.39 69.19 65.84 66.21 65.18
NGL, per barrel 20.87 28.98 47.44 — 37.75 47.75 23.64
Natural gas, per thousand cubic feet 1.08 1.21 11.88 5.46 5.48 7.72 4.28
Bitumen, per barrel — 46.13 — — — — 46.13
Synthetic oil, per barrel — 63.61 — — — — 63.61
Average production costs, per oil-equivalent barrel - total 11.13 15.63 48.26 18.43 3.75 5.60 10.20
Average production costs, per barrel - bitumen — 19.95 — — — — 19.95
Average production costs, per barrel - synthetic oil — 40.41 — — — — 40.41
2024
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 73.36 79.47 74.07 81.29 78.40 79.83 76.57
NGL, per barrel 23.08 30.43 63.29 50.51 32.34 38.74 24.32
Natural gas, per thousand cubic feet 0.37 1.72 10.56 2.25 2.55 8.47 3.13
Bitumen, per barrel — 54.02 — — — — 54.02
Synthetic oil, per barrel — 74.16 — — — — 74.16
Average production costs, per oil-equivalent barrel - total 10.89 16.20 25.18 21.85 5.31 6.92 11.70
Average production costs, per barrel - bitumen — 21.16 — — — — 21.16
Average production costs, per barrel - synthetic oil — 44.44 — — — — 44.44
Equity Companies
Average production prices
Crude oil, per barrel 73.91 — 76.34 73.99 73.17 — 73.21
NGL, per barrel 19.94 — — — 47.63 — 47.19
Natural gas, per thousand cubic feet 1.59 — 9.19 4.10 7.52 — 7.41
Average production costs, per oil-equivalent barrel - total 26.41 — 63.76 7.27 2.70 — 4.57
Total
Average production prices
Crude oil, per barrel 73.36 79.47 75.06 81.25 76.69 79.83 76.23
NGL, per barrel 23.07 30.43 63.29 50.51 43.01 38.74 27.16
Natural gas, per thousand cubic feet 0.37 1.72 10.17 3.55 6.17 8.47 4.53
Bitumen, per barrel — 54.02 — — — — 54.02
Synthetic oil, per barrel — 74.16 — — — — 74.16
Average production costs, per oil-equivalent barrel - total 10.94 16.20 36.41 20.68 3.93 6.92 10.53
Average production costs, per barrel - bitumen — 21.16 — — — — 21.16
Average production costs, per barrel - synthetic oil — 44.44 — — — — 44.44

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(dollars per unit) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total
2023
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 75.45 80.51 71.99 82.70 79.50 70.26 78.43
NGL, per barrel 23.88 24.44 64.10 44.72 29.81 34.35 25.12
Natural gas, per thousand cubic feet 1.16 2.57 13.64 2.04 2.40 9.31 4.26
Bitumen, per barrel — 49.64 — — — — 49.64
Synthetic oil, per barrel — 77.56 — — — — 77.56
Average production costs, per oil-equivalent barrel - total 9.70 19.94 36.37 20.70 5.26 5.55 12.05
Average production costs, per barrel - bitumen — 23.80 — — — — 23.80
Average production costs, per barrel - synthetic oil — 45.91 — — — — 45.91
Equity Companies
Average production prices
Crude oil, per barrel 75.48 — 77.82 71.92 74.59 — 74.63
NGL, per barrel 19.13 — — — 45.64 — 45.19
Natural gas, per thousand cubic feet 5.25 — 22.22 5.89 8.54 — 9.15
Average production costs, per oil-equivalent barrel - total 53.49 — 43.99 6.74 2.77 — 5.09
Total
Average production prices
Crude oil, per barrel 75.45 80.51 74.13 82.66 77.83 70.26 77.92
NGL, per barrel 23.86 24.44 64.10 44.72 40.59 34.35 28.66
Natural gas, per thousand cubic feet 1.19 2.57 16.71 4.81 6.93 9.31 6.05
Bitumen, per barrel — 49.64 — — — — 49.64
Synthetic oil, per barrel — 77.56 — — — — 77.56
Average production costs, per oil-equivalent barrel - total 10.15 19.94 39.09 19.79 3.91 5.55 10.63
Average production costs, per barrel - bitumen — 23.80 — — — — 23.80
Average production costs, per barrel - synthetic oil — 45.91 — — — — 45.91
Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared.
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4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
2025 2024 2023
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States 2 2 —
Canada/Other Americas 1 3 1
Europe 1 — 1
Africa — — —
Asia — — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 4 5 2
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total productive exploratory wells drilled 4 5 2
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States — — 1
Canada/Other Americas 1 3 3
Europe 1 — —
Africa 1 — —
Asia — — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 3 3 4
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total dry exploratory wells drilled 3 3 4

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2025 2024 2023
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States 698 533 446
Canada/Other Americas 14 22 47
Europe 1 1 1
Africa 1 4 4
Asia 5 6 5
Australia/Oceania 1 1 —
Total Consolidated Subsidiaries 720 567 503
Equity Companies
United States 1 1 2
Europe 1 — —
Africa — — —
Asia 3 3 6
Total Equity Companies 5 4 8
Total productive development wells drilled 725 571 511
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States — 10 —
Canada/Other Americas — — —
Europe — — —
Africa — 1 —
Asia 1 — —
Australia/Oceania — — —
Total Consolidated Subsidiaries 1 11 —
Equity Companies
United States — — —
Europe — — —
Africa — — —
Asia — — —
Total Equity Companies — — —
Total dry development wells drilled 1 11 —
Total number of net wells drilled 733 590 517

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B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies
Syncrude Operations.
Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2025, the Company’s share of net production of synthetic crude oil was about 68 thousand barrels per day and share of net acreage was about 55 thousand acres in the Athabasca oil sands deposit.
Kearl Operations.
Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 49 thousand acres in the Athabasca oil sands deposit.
Kearl is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands and processed through bitumen extraction and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation. During 2025, average net production at Kearl was about 264 thousand barrels per day.

5. Present Activities
A. Wells Drilling
Wells Drilling Year-End 2025 Year-End 2024
Gross Net Gross Net
Consolidated Subsidiaries
United States 638 492 809 648
Canada/Other Americas 33 20 19 9
Europe — — 1 1
Africa 2 — 5 1
Asia 9 2 13 5
Australia/Oceania 1 — 1 —
Total Consolidated Subsidiaries 683 514 848 664
Equity Companies
United States 38 — 15 —
Europe — — — —
Africa — — — —
Asia 23 4 43 4
Total Equity Companies 61 4 58 4
Total gross and net wells drilling 744 518 906 668

B. Review of Principal Ongoing Activities
United States

During 2025, ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. During the year, development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico, bringing total U.S. net production to 2.1 million oil-equivalent barrels per day. Development activities also continued on the Golden Pass LNG export project, including mechanical completion of Train 1 in late 2025.
Oil and gas exploration and production rights are acquired from mineral interest owners through a lease. Mineral interest owners include the Federal and State governments, as well as private mineral interest owners. Leases typically have a primary term ranging from one to 10 years, and a production period beyond the primary term that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its primary term even if production has not commenced. In some instances a “fee interest” is acquired in private property where the underlying mineral interests and rights are purchased and owned outright.
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Canada / Other Americas

Production operations for the region are mainly in Canada, Guyana, and Brazil. Total operations in Canada provided 519 thousand oil-equivalent barrels per day in net production, where oil and gas operations are active onshore in Alberta and offshore in Newfoundland and Labrador. In Situ Bitumen operations also continue in Alberta. Canadian onshore licenses or leases are acquired for varying periods of time, with renewals or extensions possible. These licenses or leases generally define a specified scope of work and are held by production. Canadian offshore production licenses are valid for 25 years, with rights of extension for continued production. Significant discovery licenses in the offshore relating to currently undeveloped discoveries do not have a definite term.
In Guyana, the Yellowtail development commenced operations with the ONE GUYANA floating production, storage and offloading vessel, and development activities continued on the Uaru and Whiptail projects. The Hammerhead project was funded in 2025. The Petroleum Activities Act 2023 authorizes the Government of Guyana to license and enter petroleum agreements for petroleum exploration, development, production, and storage operations. The Act enables petroleum agreements to provide for an exploration period to be established by subsidiary legislation by the Minister (typically up to 10 years) and provide for a production period of 20 years for an oil field and 30 years for a gas field, each with a renewal period of up to 10 years.
Brazil commenced operations in the Bacalhau Phase 1 development with the start-up of the floating production, storage and offloading vessel.
Europe

The Pegasus-1 exploratory well was drilled offshore Cyprus and encountered a gas-bearing reservoir. Evaluations are ongoing to develop potential commercialization options.
Africa

ExxonMobil continued to participate in the Coral South Floating LNG in Mozambique, while operations continued in three producing deepwater blocks in Angola and three producing deepwater blocks in Nigeria. In Angola, a total of 1.6 net acres were relinquished and Block 15 amended its Production Sharing Agreement to extend the production license to 2037.
Asia

In 2025, ExxonMobil exited Thailand operations, while production activities continued throughout the region. Kazakhstan operations take place onshore and offshore through our partnerships in Tengiz and Kashagan. During the year, the Tengiz Expansion Project was completed and production ramped up to name-plate capacity. In Qatar, ExxonMobil participated in 45.7 million tonnes per year of gross liquefied natural gas capacity and 3.4 billion cubic feet per day of flowing gas capacity. Development activities continued on the North Field East and North Field Production Sustainment projects. Ongoing activities in the United Arab Emirates continued on the phased development of the Upper Zakum field.
Australia / Oceania

In Australia, development activities progressed on the Jansz-Io Compression Project and the Gorgon Stage 3 project was fully funded. Australia and Papua New Guinea account for 22.5 million metric tons of LNG per year.
Worldwide Exploration

Exploration activities were under way in several countries in which ExxonMobil has no established production operations and thus are not included above. Net acreage totaled 15.8 million acres at year-end 2025.
6. Delivery Commitments
ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 73 million barrels of oil and 2.9 trillion cubic feet of natural gas for the period from 2026 through 2028. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and purchases on the open market as necessary.
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7. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
Gross and Net Productive Wells Year-End 2025 Year-End 2024
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net
Consolidated Subsidiaries
United States 25,816 15,760 3,270 1,833 30,333 17,078 7,579 4,340
Canada/Other Americas 4,143 4,067 2,815 983 4,092 4,025 2,865 1,017
Europe 363 106 352 192 371 113 359 192
Africa 352 94 — — 359 94 — —
Asia 797 244 140 83 789 243 151 87
Australia/Oceania 46 8 103 38 326 48 104 40
Total Consolidated Subsidiaries 31,517 20,279 6,680 3,129 36,270 21,601 11,058 5,676
Equity Companies
United States 2,551 322 3,291 323 2,573 329 3,303 326
Europe 57 20 174 64 57 20 332 102
Africa — — 6 2 — — 6 2
Asia 239 60 142 36 233 58 150 31
Total Equity Companies 2,847 402 3,613 425 2,863 407 3,791 461
Total gross and net productive wells 34,364 20,681 10,293 3,554 39,133 22,008 14,849 6,137

 
There were 22,778 gross and 20,151 net operated wells at year-end 2025 and 25,610 gross and 22,837 net operated wells at year-end 2024. The number of wells with multiple completions was 418 gross in 2025 and 434 gross in 2024.
B. Gross and Net Developed Acreage
Gross and Net Developed Acreage (thousands of acres) Year-End 2025 Year-End 2024
Gross Net Gross Net
Consolidated Subsidiaries
United States 7,715 5,083 10,668 7,021
Canada/Other Americas (1) 1,849 1,300 1,903 1,342
Europe 918 546 954 555
Africa 1,455 428 1,455 428
Asia 1,424 422 1,473 427
Australia/Oceania 3,142 1,043 3,142 1,043
Total Consolidated Subsidiaries 16,503 8,822 19,595 10,816
Equity Companies
United States 581 113 581 113
Europe 2,612 921 3,590 1,109
Africa 178 44 178 44
Asia 630 148 665 152
Total Equity Companies 4,001 1,226 5,014 1,418
Total gross and net developed acreage 20,504 10,048 24,609 12,234
(1) Includes developed acreage in Other Americas of 348 gross and 151 net thousands of acres for 2025 and 379 gross and 190 net thousands of acres for 2024.

Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
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C. Gross and Net Undeveloped Acreage
Gross and Net Undeveloped Acreage (thousands of acres) Year-End 2025 Year-End 2024
Gross Net Gross Net
Consolidated Subsidiaries
United States 5,189 2,086 6,707 2,632
Canada/Other Americas (1) 21,599 10,760 21,457 9,842
Europe 11,908 7,752 11,988 7,770
Africa 12,712 8,060 17,476 11,301
Asia 745 215 766 227
Australia/Oceania 3,346 1,661 3,554 1,805
Total Consolidated Subsidiaries 55,499 30,534 61,948 33,577
Equity Companies
United States — — — —
Europe — — 381 110
Africa 418 104 418 104
Asia 298 19 298 19
Total Equity Companies 716 123 1,097 233
Total gross and net undeveloped acreage 56,215 30,657 63,045 33,810
(1) Includes undeveloped acreage in Other Americas of 15,407 gross and 7,527 net thousands of acres for 2025 and 14,914 gross and 6,381 net thousands of acres for 2024.

ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks, and leases. The terms and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific, contractually defined, and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Corporation may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Corporation has generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Corporation.
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Information with regard to refining and chemical capacity:
ExxonMobil manufactures, trades, and sells petroleum and petrochemical products. Our refining and chemical operations are highly integrated and encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, specialty products, feedstocks, olefins, polyolefins, and a wide variety of other products to our customers around the world.
Capacity At Year-End 2025 (1)
ExxonMobil Interest % ExxonMobil’s Share of Refining Capacity (2) Ethylene Polyethylene Polypropylene
(thousands of barrels daily) (millions of metric tons per year)
United States
Joliet Illinois ■ 100 267 — — —
Baton Rouge Louisiana ■ ▲ ● 100 523 1.1 1.3 1.0
Baytown Texas ■ ▲ ● 100 565 4.0 — 0.8
Beaumont Texas ■ ▲ ● 100 612 0.9 1.7 —
Corpus Christi Texas ● 50 — 0.9 0.7 —
Mont Belvieu Texas ● 100 — — 2.3 —
Total United States 1,967 6.9 6.0 1.8
Canada
Strathcona Alberta ■ 69.6 197 — — —
Nanticoke Ontario ■ 69.6 113 — — —
Sarnia Ontario ■ ● 69.6 124 0.3 0.5 —
Total Canada 434 0.3 0.5 —
Europe
Antwerp Belgium ■ ● 100 318 — 0.4 —
Meerhout Belgium ● 100 — — 0.5 —
Karlsruhe Germany ■ 25 78 — — —
Rotterdam Netherlands ■ ▲ ● 100 192 — — —
Fawley United Kingdom ■ ▲ ● 100 265 — — —
Fife (3) United Kingdom ● 50 — 0.4 — —
Total Europe 853 0.4 0.9 —
Asia Pacific
Fujian China ■ ● 25 67 0.3 0.2 0.2
Huizhou China ● 100 — 1.6 1.7 0.9
Singapore Singapore ■ ▲ ● 100 592 1.9 1.9 1.0
Total Asia Pacific 659 3.8 3.8 2.1
Middle East
Al Jubail Saudi Arabia ▲ ● 50 — 0.7 0.7 —
Yanbu Saudi Arabia ■ ● 50 200 1.0 0.7 0.2
Total Middle East 200 1.7 1.4 0.2
Total Worldwide 4,113 13.1 12.5 4.1
■ Energy Products ▲ Specialty Products ● Chemical Products
(1) ExxonMobil share reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobil’s interest or that portion of distillation capacity normally available to ExxonMobil.
(2) Refining capacity data is based on 100 percent of rated refinery process unit stream-day capacities to process inputs to atmospheric distillation units under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. The listing excludes refining capacity for a minor interest held through equity securities in the Laffan Refinery in Qatar for which results are reported in the Upstream segment.
(3) The Corporation announced the planned closure of the Fife Ethylene Plant, with shutdown activities expected to be completed in 2026.
Due to rounding, numbers presented above may not add up precisely to the totals indicated.

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Information with regard to retail fuel sites:
Within the Energy Products segment, retail fuels sites sell products and services throughout the world through our
Exxon
,
Esso,
and
Mobil
brands.
Number of Retail Fuel Sites At Year-End 2025
Owned/leased Distributors/resellers Total
United States — 10,206 10,206
Canada — 2,561 2,561
Europe 169 3,430 3,599
Asia Pacific 188 932 1,120
Latin America — 579 579
Middle East/Africa 168 300 468
Worldwide 525 18,008 18,533

ITEM 3. LEGAL PROCEEDINGS

ExxonMobil has elected to use a $1 million threshold for disclosing environmental proceedings.
Refer to the relevant portions of
Note 7
of the Financial Section of this report for additional information on legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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Information about our Executive Officers (positions and ages as of February 18, 2026)
Name Age Current and Prior Positions (up to five years)
Darren W. Woods 61 Chairman of the Board and Chief Executive Officer (since January 1, 2017) Director and President (since January 1, 2016)
Neil A. Chapman 63 Senior Vice President (since January 1, 2018)
Neil A. Hansen 51 Senior Vice President and Chief Financial Officer (since February 1, 2026) President, Global Business Solutions (May 1, 2025 - January 31, 2026) Senior Vice President, Energy Products, ExxonMobil Product Solutions Company (April 1, 2022 - April 30, 2025) Vice President, Europe, Africa & Middle East Fuels, ExxonMobil Fuels & Lubricants Company (March 15, 2020 - March 31, 2022)
Jack P. Williams, Jr. 62 Senior Vice President (since June 1, 2014)
Daniel L. Ammann 53 Vice President (since May 1, 2022) President, ExxonMobil Upstream Company (since February 1, 2025) President, Low Carbon Solutions (May 1, 2022 - December 31, 2024) Chief Executive Officer, Cruise LLC (January 2019 - December 2021)
James R. Chapman 56 Vice President, Treasurer and Investor Relations (since May 1, 2024) Vice President, Tax and Treasurer (November 28, 2022 - April 30, 2024) Dominion Energy, Inc. (prior to November 28, 2022): Executive Vice President, Chief Financial Officer and Treasurer (January 2019 - November 2022)
Matt R. Crocker 52 Vice President (since May 1, 2025) President, Global Business Solutions (November 1, 2023 - April 30, 2025) Senior Vice President, Strategy, Product and New Assets, Low Carbon Solutions (May 1, 2022 - October 31, 2023) Senior Vice President, Fuels and Lubricants, ExxonMobil Fuels & Lubricants Company (September 1, 2020 - April 30, 2022)
Len M. Fox 62 Vice President, Controller and Tax (since May 1, 2024) Vice President and Controller (March 1, 2021 - April 30, 2024)
Jon M. Gibbs 54 Senior President, ExxonMobil Global Operations (since January 1, 2026) President, ExxonMobil Global Projects Company (April 1, 2021 - December 31, 2025) Senior Vice President, Global Project Delivery, ExxonMobil Global Projects Company (July 1, 2020 - March 31, 2021)
Staale Gjervik 52 President, ExxonMobil Global Projects Company (since January 1, 2026) President, ExxonMobil Supply Chain (May 1, 2023 - December 31, 2025) President, ExxonMobil Global Services Company (July 1, 2020 - April 30, 2023)
Darrin L. Talley 61 Vice President, Corporate Strategic Planning (since April 1, 2022) President, ExxonMobil Research and Engineering Company (April 1, 2020 - March 31, 2022)
Jeffrey A. Taylor 61 Vice President, General Counsel and Corporate Secretary (since July 1, 2024) Deputy General Counsel (May 9, 2024 - June 30, 2024) Executive Vice President and General Counsel, Fox Corporation (March 1, 2021 - May 8, 2024) Executive Vice President and Chief Litigation Counsel, Fox Corporation (March 1, 2019 - February 28, 2021)

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified. The above-named officers are required to file reports under Section 16 of the Securities Exchange Act of 1934.
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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The principal exchange where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.
There were 276,536 registered shareholders of ExxonMobil common stock at December 31, 2025. At January 31, 2026, the registered shareholders of ExxonMobil common stock numbered 273,961.
On January 29, 2026, the Corporation declared a $1.03 dividend per common share, payable March 10, 2026.
Reference is made to
Item 12
in Part III of this report.
 
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2025
Total Number of Shares Purchased (1) Average Price Paid per Share (2) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (3) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (Billions of dollars) (4)
October 2025 16,203,130 $113.58 16,203,068 $23.3
November 2025 13,456,104 $116.69 13,025,924 $21.8
December 2025 16,753,598 $117.81 14,908,290 $20.0
Total 46,412,832 $116.01 44,137,282
(1) Includes shares withheld from participants in the Company's incentive program for personal income taxes.
(2) Excludes 1% U.S. excise tax on stock repurchases.
(3) Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1.
(4) The Corporation completed share repurchases of $20 billion in 2025. In its 2025 Corporate Plan Update released December 9, 2025, the Corporation stated that it expects share repurchases of $20 billion in 2026, assuming reasonable market conditions.

 During the fourth quarter, the Corporation did not issue or sell any unregistered equity securities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Reference is made to the section entitled “
Management’s Discussion and Analysis of Financial Condition and Results of Operations
” in the Financial Section of this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Reference is made to the section entitled “
Market Risks
” in the Financial Section of this report. All statements, other than historical information incorporated in this Item 7A, are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the following in the Financial Section of this report:
•

Consolidated financial statements
, together with the report thereon of PricewaterhouseCoopers LLP (PCAOB ID
238
) dated February 18, 2026, beginning with the section entitled “
Report of Independent Registered Public Accounting Firm
” and continuing through
Note

20
;
•
“
Supplemental Information on Oil and Gas Exploration and Production Activities
” (unaudited); and
•
“
Frequently Used Terms
” (unaudited).
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.
ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2025. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Management’s Report on Internal Control over Financial Reporting
Management, including the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in
Internal Control - Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 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.
Changes in Internal Control over Financial Reporting
There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.
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ITEM 9B. OTHER INFORMATION

During the three months ended December 31, 2025,
none of the Company’s directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Reference is made to the section of this report titled “
Information about our Executive Officers
.”
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2026 annual meeting of shareholders (the “2026 Proxy Statement”):
•
The section entitled “Election of Directors;”
•
The portion entitled "Delinquent Section 16(a) Reports" of the section entitled "Director and Executive Officer Stock Ownership;"
•
The portions entitled “Director Qualifications,” “Director Nomination Process and Board Succession,” and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance;” and
•
The “Director Independence” portion, “Board Meetings and Annual Meeting Attendance” portion, the membership table of the portion entitled “Board Committees,” the "Nominating and Governance Committee" portion and the "Audit Committee" portion of the section entitled “Corporate Governance.”
The Corporation has adopted an Insider Trading Policy governing the purchase, sale, and/or other dispositions of its securities by its directors, officers, and employees, and the Corporation itself, that the Corporation believes is reasonably designed to promote compliance with insider trading laws, rules and regulations, and the exchange listing standards applicable to the Corporation. A copy of the Corporation’s Insider Trading Policy is filed as Exhibit 19 to this report.
ITEM 11. EXECUTIVE COMPENSATION

Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis,” “Executive Compensation Tables,” “Pay Ratio,” and "Pay Versus Performance" of the registrant’s 2026 Proxy Statement.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections entitled “Certain Beneficial Owners” and “Director and Executive Officer Stock Ownership” of the registrant’s 2026 Proxy Statement.
Equity Compensation Plan Information
(a) (b) (c)
Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans [Excluding Securities Reflected in Column (a)]
Equity compensation plans approved by security holders 45,870,110 (1) — 50,547,885 (2)(3)
Equity compensation plans not approved by security holders — — —
Total 45,870,110 — 50,547,885
(1) The number of restricted stock units to be settled in shares.
(2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 40,903,325 shares available for award under the 2003 Incentive Program, 218,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan, and 9,425,860 shares available for award under the Pioneer Natural Resources Company Amended and Restated 2006 Long Term Incentive Plan.
(3) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Incorporated by reference to the portion entitled “Director Independence” of the section entitled “Corporate Governance” and the portion entitled “Related Person Transactions and Procedures” of the section entitled “Director and Executive Officer Stock Ownership” of the registrant’s 2026 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2026 Proxy Statement.
PART IV
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES

(a)
(1) and (2) Financial Statements:
See
Table of Contents
of the Financial Section of this report.
(b)
(3) Exhibits:
See
Index to Exhibits
of this report.
ITEM 16. FORM 10-K SUMMARY

None.
27
FINANCIAL SECTION
TABLE OF CONTENTS
Business Profile 29
Financial Information 30
Frequently Used Terms 31
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements 36
Overview 37
Business Environment 38
Business Results 44
Liquidity and Capital Resources 58
Taxes 61
Environmental Matters 62
Market Risks 62
Critical Accounting Estimates 63
Management’s Report on Internal Control over Financial Reporting 68
Report of Independent Registered Public Accounting Firm 69
Consolidated Financial Statements
Statement of Income 71
Statement of Comprehensive Income 72
Balance Sheet 73
Statement of Cash Flows 74
Statement of Changes in Equity 75
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies 76
2. Earnings Per Share 80
3. Disclosures about Segments and Related Information 80
4. Pension and Other Postretirement Benefits 85
5. Other Comprehensive Income Information 92
6. Financial Instruments and Derivatives 93
7. Litigation and Other Contingencies 94
8. Equity Company Information 95
9. Property, Plant , and Equipment and Asset Retirement Obligations 97
10. Additional Working Capital Information 99
11. Investments, Advances , and Long-Term Receivables 99
12. Long-Term Debt 100
13. Leases 102
14. Miscellaneous Financial Information 103
15. Income and Other Taxes 104
16. Accounting for Suspended Exploratory Well Costs 109
17. Cash Flow Information 110
18. Incentive Program 110
19. Divestment Activities 112
20. Mergers and Acquisitions 112
Supplemental Information on Oil and Gas Exploration and Production Activities 114

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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 2025 2024 2025 2024 2025 2024 2025 2024
(millions of dollars) (millions of dollars) (percent) (millions of dollars)
Upstream
United States 5,063 6,426 118,142 85,285 4.3 7.5 15,907 11,276
Non-U.S. 16,291 18,964 91,792 93,390 17.7 20.3 8,752 8,985
Total 21,354 25,390 209,934 178,675 10.2 14.2 24,659 20,261
Energy Products
United States 2,992 2,099 13,495 13,190 22.2 15.9 752 705
Non-U.S. 4,431 1,934 24,188 21,135 18.3 9.2 955 1,513
Total 7,423 4,033 37,683 34,325 19.7 11.7 1,707 2,218
Chemical Products
United States 903 1,627 14,207 14,277 6.4 11.4 843 671
Non-U.S. (103) 950 15,303 14,760 (0.7) 6.4 552 1,212
Total 800 2,577 29,510 29,037 2.7 8.9 1,395 1,883
Specialty Products
United States 1,200 1,576 2,025 2,035 59.3 77.4 381 145
Non-U.S. 1,657 1,476 6,048 6,183 27.4 23.9 242 263
Total 2,857 3,052 8,073 8,218 35.4 37.1 623 408
Corporate and Financing (3,590) (1,372) 20,575 27,847 — — 613 877
Corporate total 28,844 33,680 305,775 278,102 9.3 12.7 28,997 25,647
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 2025 2024 2025 2024
Net liquids production (thousands of barrels daily) Refinery throughput (thousands of barrels daily)
United States 1,522 1,248 United States 1,927 1,865
Non-U.S. 1,805 1,739 Non-U.S. 2,052 2,035
Total 3,329 2,987 Total 3,979 3,900
Natural gas production available for sale (millions of cubic feet daily) Energy Products sales (2) (thousands of barrels daily)
United States 3,364 2,887 United States 2,852 2,722
Non-U.S. 5,077 5,191 Non-U.S. 2,740 2,696
Total 8,442 8,078 Total 5,593 5,418
Oil-equivalent production (1) (thousands of oil-equivalent barrels daily) 4,736 4,333 Chemical Products sales (2) (thousands of metric tons)
United States 6,977 7,038
Non-U.S. 14,326 12,354
Total 21,303 19,392
Specialty Products sales (2) (thousands of metric tons)
United States 1,894 1,922
Non-U.S. 5,897 5,745
Total 7,791 7,666
(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) 2025 2024 2023
Sales and other operating revenue 323,905 339,247 334,697
Net income (loss) attributable to ExxonMobil 28,844 33,680 36,010
Earnings (loss) per common share (dollars) 6.70 7.84 8.89
Earnings (loss) per common share – assuming dilution (dollars) 6.70 7.84 8.89
Earnings (loss) to average ExxonMobil share of equity (percent) 11.0 14.4 18.0
Working capital 11,052 21,683 31,293
Ratio of current assets to current liabilities (times) 1.15 1.31 1.48
Additions to property, plant, and equipment (1) 31,476 109,332 29,038
Property, plant, and equipment, less allowances 299,373 294,318 214,940
Total assets 448,980 453,475 376,317
Exploration expenses, including dry holes 1,007 826 751
Research and development costs 1,228 987 879
Long-term debt 34,241 36,755 37,483
Total debt 43,537 41,710 41,573
Debt to capital (percent) 14.0 13.4 16.4
Net debt to capital (percent) (2) 11.0 6.5 4.5
ExxonMobil share of equity at year-end 259,386 263,705 204,802
ExxonMobil share of equity per common share (dollars) 62.07 60.58 51.57
Weighted-average number of common shares outstanding (millions) 4,305 4,298 4,052
Number of regular employees at year-end (thousands) (3) 57.9 60.9 61.5
(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) 2025 2024 2023
Net cash provided by operating activities 51,970 55,022 55,369
Proceeds associated with sales of subsidiaries, property, plant, and equipment, and sales and returns of investments 3,158 4,987 4,078
Cash flow from operations and asset sales (Non-GAAP) 55,128 60,009 59,447

 
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) 2025 2024 2023
Business uses: asset and liability perspective
Total assets 448,980 453,475 376,317
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable (63,034) (65,352) (61,226)
Total long-term liabilities excluding long-term debt (75,783) (75,807) (60,980)
Noncontrolling interests share of assets and liabilities (8,895) (8,069) (8,878)
Add ExxonMobil share of debt-financed equity company net assets 2,793 3,242 3,481
Total capital employed (Non-GAAP) 304,061 307,489 248,714
Total corporate sources: debt and equity perspective
Notes and loans payable 9,296 4,955 4,090
Long-term debt 34,241 36,755 37,483
ExxonMobil share of equity 259,386 263,705 204,802
Less noncontrolling interests share of total debt (1,655) (1,168) (1,142)
Add ExxonMobil share of equity company debt 2,793 3,242 3,481
Total capital employed (Non-GAAP) 304,061 307,489 248,714

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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) 2025 2024 2023
Net income (loss) attributable to ExxonMobil 28,844 33,680 36,010
Financing costs (after-tax)
Gross third-party debt (1,360) (1,106) (1,175)
ExxonMobil share of equity companies (165) (196) (307)
All other financing costs – net 2,072 (252) 931
Total financing costs 547 (1,554) (551)
Earnings (loss) excluding financing costs (Non-GAAP) 28,297 35,234 36,561
Average capital employed (Non-GAAP) 305,775 278,102 243,440
Return on average capital employed – Corporate total (Non-GAAP) 9.3% 12.7% 15.0%

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) 2019 2025
Components of Operating Costs
From ExxonMobil’s Consolidated Statement of Income (U.S. GAAP)
Production and manufacturing expenses 36.8 42.4
Selling, general and administrative expenses 11.4 11.1
Depreciation and depletion (includes impairments) 19.0 26.0
Exploration expenses, including dry holes 1.3 1.0
Non-service pension and postretirement benefit expense 1.2 0.4
Subtotal 69.7 81.0
ExxonMobil’s share of equity company expenses (Non-GAAP) 9.1 10.6
Total Adjusted Operating Costs (Non-GAAP) 78.8 91.6
Total Adjusted Operating Costs (Non-GAAP) 78.8 91.6
Less:
Depreciation and depletion (includes impairments) 19.0 26.0
Non-service pension and postretirement benefit expense 1.2 0.4
Other adjustments (includes equity company depreciation and depletion) 3.6 6.2
Total Cash Operating Expenses (Cash Opex) (Non-GAAP) 55.0 59.0
Energy and production taxes (Non-GAAP) 11.0 14.9
Market Activity/ Other Structural Cost Savings
Total Cash Operating Expenses (Cash Opex) excluding Energy and Production Taxes (Non-GAAP) 44.0 +4.9 +10.3 -15.1 44.1
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 2025 2024 2023
(millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total
Earnings (loss) (U.S. GAAP) 5,063 16,291 21,354 6,426 18,964 25,390 4,202 17,106 21,308
Impairments (662) (422) (1,084) (360) (48) (408) (1,978) (686) (2,664)
Gain/(loss) on sale of assets — — — — 385 385 305 — 305
Tax-related items 192 — 192 — 238 238 184 (126) 58
Identified Items (471) (422) (893) (360) 575 215 (1,489) (812) (2,301)
Earnings (loss) excluding Identified Items (Non-GAAP) 5,534 16,713 22,247 6,786 18,389 25,175 5,691 17,918 23,609

Energy Products 2025 2024 2023
(millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total
Earnings (loss) (U.S. GAAP) 2,992 4,431 7,423 2,099 1,934 4,033 6,123 6,019 12,142
Impairments (153) (113) (266) (34) (59) (93) — — —
Gain/(loss) on sale of assets — 720 720 — — — — — —
Tax-related items 34 (6) 28 — 172 172 192 (48) 144
Identified Items (118) 601 483 (34) 113 79 192 (48) 144
Earnings (loss) excluding Identified Items (Non-GAAP) 3,110 3,830 6,940 2,133 1,821 3,954 5,931 6,067 11,998

Chemical Products 2025 2024 2023
(millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total
Earnings (loss) (U.S. GAAP) 903 (103) 800 1,627 950 2,577 1,626 11 1,637
Impairments (130) (190) (320) (43) (52) (95) (21) (273) (294)
Tax-related items 50 — 50 — — — 53 — 53
Other — — — — — — — (147) (147)
Identified Items (80) (190) (270) (43) (52) (95) 32 (420) (388)
Earnings (loss) excluding Identified Items (Non-GAAP) 983 87 1,070 1,670 1,002 2,672 1,594 431 2,025

Specialty Products 2025 2024 2023
(millions of dollars) U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total
Earnings (loss) (U.S. GAAP) 1,200 1,657 2,857 1,576 1,476 3,052 1,536 1,178 2,714
Impairments (18) (12) (30) (4) (8) (12) — (82) (82)
Tax-related items 30 — 30 — (1) (1) 12 5 17
Other — — — — — — — (28) (28)
Identified Items 12 (12) — (4) (9) (13) 12 (105) (93)
Earnings (loss) excluding Identified Items (Non-GAAP) 1,188 1,669 2,857 1,580 1,485 3,065 1,524 1,283 2,807

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FREQUENTLY USED TERMS
Corporate and Financing (millions of dollars) 2025 2024 2023
Earnings (loss) (U.S. GAAP) (3,590) (1,372) (1,791)
Impairments (155) — —
Gain/(loss) on sale of assets — 30 —
Tax-related items (11) — 76
Restructuring charges (419) — —
Identified Items (585) 30 76
Earnings (loss) excluding Identified Items (Non-GAAP) (3,005) (1,402) (1,867)

Corporate Total (millions of dollars) 2025 2024 2023
Net income (loss) attributable to ExxonMobil (U.S. GAAP) 28,844 33,680 36,010
Impairments (1,855) (608) (3,040)
Gain/(loss) on sale of assets 720 415 305
Tax-related items 288 409 348
Restructuring charges (419) — —
Other — — (175)
Identified Items (1,265) 216 (2,562)
Earnings (loss) excluding Identified Items (Non-GAAP) 30,109 33,464 38,572

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) 2025 2024
Additions to property, plant, and equipment 28,358 24,306
Additional investments and advances 4,133 3,299
Other investing activities including collection of advances (3,406) (1,926)
Inflows from noncontrolling interests for major projects (88) (32)
Total Cash Capex (Non-GAAP) 28,997 25,647

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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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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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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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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) 2025 2024 2023
Earnings (loss) (U.S. GAAP)
United States 5,063 6,426 4,202
Non-U.S. 16,291 18,964 17,106
Total 21,354 25,390 21,308
Identified Items (1)
United States (471) (360) (1,489)
Non-U.S. (422) 575 (812)
Total (893) 215 (2,301)
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States 5,534 6,786 5,691
Non-U.S. 16,713 18,389 17,918
Total 22,247 25,175 23,609

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
2025 2024 2023
Net production of crude oil, natural gas liquids, bitumen and synthetic oil (thousands of barrels daily)
United States 1,522 1,248 803
Canada/Other Americas 835 784 664
Europe 3 3 4
Africa 142 209 221
Asia 800 713 721
Australia/Oceania 25 30 36
Worldwide 3,329 2,987 2,449
Net natural gas production available for sale (millions of cubic feet daily)
United States 3,364 2,887 2,311
Canada/Other Americas 27 101 96
Europe 299 352 414
Africa 114 152 125
Asia 3,354 3,322 3,490
Australia/Oceania 1,283 1,264 1,298
Worldwide 8,442 8,078 7,734
Oil-equivalent production (1) (thousands of oil-equivalent barrels daily) 4,736 4,333 3,738
(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) 2025 2024
Volumes Reconciliation (Oil-equivalent production) (1)
Prior Year 4,333 3,738
Entitlements - Net Interest (33) (13)
Entitlements - Price / Spend / Other 45 (23)
Government Mandates (1) 9
Divestments (133) (63)
Growth / Other 525 685
Current Year 4,736 4,333
(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) 2025 2024 2023
Earnings (loss) (U.S. GAAP)
United States 2,992 2,099 6,123
Non-U.S. 4,431 1,934 6,019
Total 7,423 4,033 12,142
Identified Items (1)
United States (118) (34) 192
Non-U.S. 601 113 (48)
Total 483 79 144
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States 3,110 2,133 5,931
Non-U.S. 3,830 1,821 6,067
Total 6,940 3,954 11,998
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) 2025 2024 2023
Refinery throughput
United States 1,927 1,865 1,848
Canada 402 399 407
Europe 1,002 1,039 1,166
Asia Pacific 460 432 498
Other 188 165 149
Worldwide 3,979 3,900 4,068
Energy Products sales (1)
United States 2,852 2,722 2,633
Non-U.S. 2,740 2,696 2,828
Worldwide 5,593 5,418 5,461
Gasoline, naphthas 2,290 2,251 2,288
Heating oils, kerosene, diesel 1,791 1,769 1,795
Aviation fuels 383 355 336
Heavy fuels 220 200 214
Other energy products 910 844 829
Worldwide 5,593 5,418 5,461
(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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Chemical Products Financial Results
(millions of dollars) 2025 2024 2023
Earnings (loss) (U.S. GAAP)
United States 903 1,627 1,626
Non-U.S. (103) 950 11
Total 800 2,577 1,637
Identified Items (1)
United States (80) (43) 32
Non-U.S. (190) (52) (420)
Total (270) (95) (388)
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States 983 1,670 1,594
Non-U.S. 87 1,002 431
Total 1,070 2,672 2,025

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) 2025 2024 2023
Chemical Products sales (2)
United States 6,977 7,038 6,779
Non-U.S. 14,326 12,354 12,603
Worldwide 21,303 19,392 19,382
(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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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) 2025 2024 2023
Earnings (loss) (U.S. GAAP)
United States 1,200 1,576 1,536
Non-U.S. 1,657 1,476 1,178
Total 2,857 3,052 2,714
Identified Items (1)
United States 12 (4) 12
Non-U.S. (12) (9) (105)
Total — (13) (93)
Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States 1,188 1,580 1,524
Non-U.S. 1,669 1,485 1,283
Total 2,857 3,065 2,807
(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) 2025 2024 2023
Specialty Products sales (2)
United States 1,894 1,922 1,962
Non-U.S. 5,897 5,745 5,635
Worldwide 7,791 7,666 7,597
(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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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) 2025 2024 2023
Earnings (loss) (U.S. GAAP) (3,590) (1,372) (1,791)
Identified Items (1) (585) 30 76
Earnings (loss) excluding Identified Items (1) (Non-GAAP) (3,005) (1,402) (1,867)
(1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items.

2025 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.
2024 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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LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
(millions of dollars) 2025 2024 2023
Net cash provided by/(used in)
Operating activities 51,970 55,022 55,369
Investing activities (25,927) (19,938) (19,274)
Financing activities (39,081) (42,789) (34,297)
Effect of exchange rate changes 532 (676) 105
Increase/(decrease) in cash and cash equivalents (12,506) (8,381) 1,903
Total cash and cash equivalents (December 31) 10,681 23,187 31,568

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
2025
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.
2024
Cash provided by operating activities totaled $55.0 billion in 2024, $0.3 billion lower than 2023. The major source of funds was net income including noncontrolling interests of $35.1 billion, a decrease of $2.3 billion. The noncash provision for depreciation and depletion was $23.4 billion, up $2.8 billion from the prior year. The adjustment for the net gain on asset sales was $1.2 billion, an increase of $0.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $0.2 billion, compared to an increase of $0.5 billion in 2023. Changes in operational working capital, excluding cash and debt, decreased cash in 2024 by $1.8 billion.
 
Cash Flow from Investing Activities
2025
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.
2024
Cash used in investing activities netted to $19.9 billion in 2024, $0.7 billion higher than 2023. Spending for property, plant, and equipment of $24.3 billion increased $2.4 billion from 2023. Proceeds from asset sales and returns of investments of $5.0 billion compared to $4.1 billion in 2023. Additional investments and advances were $0.3 billion higher in 2024, while proceeds from other investing activities including collection of advances increased by $0.4 billion. 
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Cash Flow from Financing Activities
2025
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.
2024
Cash used in financing activities was $42.8 billion in 2024, $8.5 billion higher than 2023. Dividend payments on common shares increased to $3.84 per share from $3.68 per share and totaled $16.7 billion.
During 2024, the Corporation utilized cash to repay debt of $5.9 billion.
During 2024, the Corporation continued its share repurchase program, including the purchase of 167 million shares at a book value of $19.1 billion in 2024.
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) 2025 2024 2023
Debt to capital 14.0 13.4 16.4
Net debt to capital (1) 11.0 6.5 4.5
(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) 2025 2024 2023
Income taxes 11,504 13,810 15,429
Effective income tax rate 31% 33% 33%
Total other taxes and duties 28,930 29,894 32,191
Total 40,434 43,704 47,620

2025
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.
2024
Total taxes on the Corporation’s income statement were $43.7 billion in 2024, a decrease of $3.9 billion from 2023. Income tax expense, both current and deferred, was $13.8 billion compared to $15.4 billion in 2023. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This 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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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENVIRONMENTAL MATTERS
Environmental Expenditures
(millions of dollars) 2025 2024
Capital expenditures 3,053 3,607
Other expenditures 4,580 5,348
Total 7,633 8,955

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 $0.7 billion as of December 31, 2024.
MARKET RISKS
Worldwide Average Realizations (1) 2025 2024 2023
Brent ($ per barrel) 69.06 80.76 82.62
Henry Hub ($ per metric million British thermal unit) 3.43 2.27 2.74
TTF ($ per metric million British thermal unit) 12.39 10.77 15.15
(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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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2025 2024 2023
Revenues and other income
Sales and other operating revenue 3 323,905 339,247 334,697
Income from equity affiliates 8 5,064 6,194 6,385
Other income 3,269 4,144 3,500
Total revenues and other income 332,238 349,585 344,582
Costs and other deductions
Crude oil and product purchases 184,248 199,454 193,029
Production and manufacturing expenses 42,424 39,609 36,885
Selling, general and administrative expenses 11,128 9,976 9,919
Depreciation and depletion (includes impairments) 9 25,993 23,442 20,641
Exploration expenses, including dry holes 1,007 826 751
Non-service pension and postretirement benefit expense 4 400 121 714
Interest expense 603 996 849
Other taxes and duties 15 25,167 26,288 29,011
Total costs and other deductions 290,970 300,712 291,799
Income (loss) before income taxes 41,268 48,873 52,783
Income tax expense (benefit) 15 11,504 13,810 15,429
Net income (loss) including noncontrolling interests 29,764 35,063 37,354
Net income (loss) attributable to noncontrolling interests 920 1,383 1,344
Net income (loss) attributable to ExxonMobil 28,844 33,680 36,010
Earnings (loss) per common share (dollars) 2 6.70 7.84 8.89
Earnings (loss) per common share - assuming dilution (dollars) 2 6.70 7.84 8.89

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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) 2025 2024 2023
Net income (loss) including noncontrolling interests 29,764 35,063 37,354
Other comprehensive income (loss) (net of income taxes)
Foreign exchange translation adjustment 2,631 ( 3,550 ) 1,241
Adjustment for foreign exchange translation (gain)/loss included in net income 391 — 609
Postretirement benefits reserves adjustment (excluding amortization) 1,009 557 ( 369 )
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs 38 43 61
Total other comprehensive income (loss) 4,069 ( 2,950 ) 1,542
Comprehensive income (loss) including noncontrolling interests 33,833 32,113 38,896
Comprehensive income (loss) attributable to noncontrolling interests 1,233 1,063 1,605
Comprehensive income (loss) attributable to ExxonMobil 32,600 31,050 37,291

 
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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 10,681 23,029
Cash and cash equivalents – restricted — 158
Notes and accounts receivable – net 10 44,562 43,681
Inventories
Crude oil, products and merchandise 14 22,979 19,444
Materials and supplies 3,323 4,080
Other current assets 1,837 1,598
Total current assets 83,382 91,990
Investments, advances, and long-term receivables 11 45,317 47,200
Property, plant, and equipment, at cost, less accumulated depreciation and depletion 9 299,373 294,318
Other assets, including intangibles – net 20,908 19,967
Total Assets 448,980 453,475
LIABILITIES
Current liabilities
Notes and loans payable 10 9,296 4,955
Accounts payable and accrued liabilities 10 60,911 61,297
Income taxes payable 2,123 4,055
Total current liabilities 72,330 70,307
Long-term debt 12 34,241 36,755
Postretirement benefits reserves 4 8,847 9,700
Deferred income tax liabilities 15 40,216 39,042
Long-term obligations to equity companies 542 1,346
Other long-term obligations 26,178 25,719
Total Liabilities 182,354 182,869
Commitments and contingencies 7
EQUITY
Common stock without par value ( 9,000 million shares authorized, 8,019 million shares issued) 46,150 46,238
Earnings reinvested 482,494 470,903
Accumulated other comprehensive income 5 ( 10,863 ) ( 14,619 )
Common stock held in treasury ( 3,840 million shares in 2025 and 3,666 million shares in 2024) ( 258,395 ) ( 238,817 )
ExxonMobil share of equity 259,386 263,705
Noncontrolling interests 7,240 6,901
Total Equity 266,626 270,606
Total Liabilities and Equity 448,980 453,475

 
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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 2025 2024 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) including noncontrolling interests 29,764 35,063 37,354
Adjustments for noncash transactions
Depreciation and depletion (includes impairments) 9 25,993 23,442 20,641
Deferred income tax charges/(credits) 15 765 ( 865 ) 634
Postretirement benefits expense in excess of/(less than) net payments ( 64 ) ( 358 ) 90
Other long-term obligation provisions in excess of/(less than) payments ( 1,430 ) ( 1,712 ) ( 1,501 )
Dividends received greater than/(less than) equity in current earnings of equity companies 3,006 191 509
Changes in operational working capital, excluding cash and debt
Notes and accounts receivable reduction/(increase) ( 3,042 ) ( 6,030 ) 4,370
Inventories reduction/(increase) ( 4,300 ) ( 1,812 ) ( 3,472 )
Other current assets reduction/(increase) ( 164 ) 389 ( 426 )
Accounts and other payables increase/(reduction) ( 222 ) 5,627 ( 4,727 )
Net (gain)/loss on asset sales 17 ( 1,113 ) ( 1,223 ) ( 513 )
All other items - net 2,777 2,310 2,410
Net cash provided by operating activities 51,970 55,022 55,369
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, and equipment ( 28,358 ) ( 24,306 ) ( 21,919 )
Proceeds from asset sales and returns of investments 3,158 4,987 4,078
Additional investments and advances ( 4,133 ) ( 3,299 ) ( 2,995 )
Other investing activities including collection of advances 3,406 1,926 1,562
Cash acquired from mergers and acquisitions — 754 —
Net cash used in investing activities ( 25,927 ) ( 19,938 ) ( 19,274 )
CASH FLOWS FROM FINANCING ACTIVITIES
Additions to long-term debt (1) 2,311 899 939
Reductions in long-term debt ( 1,108 ) ( 1,150 ) ( 15 )
Additions to short-term debt (2) (3) 2,359 — —
Reductions in short-term debt (3) ( 5,404 ) ( 4,743 ) ( 879 )
Additions/(reductions) in commercial paper, and debt with three months or less maturity 1,895 ( 18 ) ( 284 )
Contingent consideration payments ( 79 ) ( 27 ) ( 68 )
Cash dividends to ExxonMobil shareholders ( 17,231 ) ( 16,704 ) ( 14,941 )
Cash dividends to noncontrolling interests ( 935 ) ( 658 ) ( 531 )
Changes in noncontrolling interests ( 704 ) ( 791 ) ( 894 )
Inflows from noncontrolling interests for major projects 88 32 124
Common stock acquired ( 20,273 ) ( 19,629 ) ( 17,748 )
Net cash provided by (used in) financing activities ( 39,081 ) ( 42,789 ) ( 34,297 )
Effects of exchange rate changes on cash 532 ( 676 ) 105
Increase/(decrease) in cash and cash equivalents (including restricted) ( 12,506 ) ( 8,381 ) 1,903
Cash and cash equivalents at beginning of year (including restricted) 23,187 31,568 29,665
Cash and cash equivalents at end of year (including restricted) 10,681 23,187 31,568
(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 15,752 432,860 ( 13,270 ) ( 240,293 ) 195,049 7,424 202,473
Amortization of stock-based awards 565 — — — 565 — 565
Other ( 514 ) ( 2 ) — — ( 516 ) 89 ( 427 )
Net income (loss) for the year — 36,010 — — 36,010 1,344 37,354
Dividends - common shares — ( 14,941 ) — — ( 14,941 ) ( 531 ) ( 15,472 )
Other comprehensive income — — 1,281 — 1,281 261 1,542
Share repurchases, at cost — — — ( 17,993 ) ( 17,993 ) ( 851 ) ( 18,844 )
Issued for acquisitions 1,978 — — 2,866 4,844 — 4,844
Dispositions — — — 503 503 — 503
Balance as of December 31, 2023 17,781 453,927 ( 11,989 ) ( 254,917 ) 204,802 7,736 212,538
Amortization of stock-based awards 735 — — — 735 — 735
Other ( 1,027 ) — — — ( 1,027 ) ( 624 ) ( 1,651 )
Net income (loss) for the year — 33,680 — — 33,680 1,383 35,063
Dividends - common shares — ( 16,704 ) — — ( 16,704 ) ( 658 ) ( 17,362 )
Other comprehensive income — — ( 2,630 ) — ( 2,630 ) ( 320 ) ( 2,950 )
Share repurchases, at cost — — — ( 19,451 ) ( 19,451 ) ( 616 ) ( 20,067 )
Issued for acquisitions 28,749 — — 34,603 63,352 — 63,352
Dispositions — — — 948 948 — 948
Balance as of December 31, 2024 46,238 470,903 ( 14,619 ) ( 238,817 ) 263,705 6,901 270,606
Amortization of stock-based awards 812 — — — 812 — 812
Other ( 900 ) ( 22 ) — — ( 922 ) 762 ( 160 )
Net income (loss) for the year — 28,844 — — 28,844 920 29,764
Dividends - common shares — ( 17,231 ) — — ( 17,231 ) ( 947 ) ( 18,178 )
Other comprehensive income — — 3,756 — 3,756 313 4,069
Share repurchases, at cost — — — ( 20,467 ) ( 20,467 ) ( 709 ) ( 21,176 )
Dispositions — — — 889 889 — 889
Balance as of December 31, 2025 46,150 482,494 ( 10,863 ) ( 258,395 ) 259,386 7,240 266,626

Common Stock Share Activity (millions of shares) Issued Held in Treasury Outstanding
Balance as of December 31, 2022 8,019 ( 3,937 ) 4,082
Share repurchases, at cost — ( 165 ) ( 165 )
Issued for acquisitions — 46 46
Dispositions — 8 8
Balance as of December 31, 2023 8,019 ( 4,048 ) 3,971
Share repurchases, at cost — ( 170 ) ( 170 )
Issued for acquisitions — 545 545
Dispositions — 7 7
Balance as of December 31, 2024 8,019 ( 3,666 ) 4,353
Share repurchases, at cost — ( 182 ) ( 182 )
Issued for acquisitions — — —
Dispositions — 8 8
Balance as of December 31, 2025 8,019 ( 3,840 ) 4,179

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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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Note 2. Earnings Per Share
Earnings per common share 2025 2024 2023
Net income (loss) attributable to ExxonMobil (millions of dollars) 28,844 33,680 36,010
Weighted-average number of common shares outstanding (millions of shares) (1) 4,305 4,298 4,052
Earnings (loss) per common share (dollars) (2) 6.70 7.84 8.89
Dividends paid per common share (dollars) 4.00 3.84 3.68
(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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(millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S.
Year ended December 31, 2025
Revenues and other income
Sales and other operating revenue 25,396 13,993 99,073 145,378 7,594 14,615 5,502 12,269 323,820
Income from equity affiliates 19 4,340 139 198 135 544 7 ( 52 ) 5,330
Intersegment revenue 25,637 36,769 19,172 26,694 6,777 3,324 2,133 499 121,005
Other income 437 560 113 849 3 ( 10 ) 13 89 2,054
Segment revenues and other income 51,489 55,662 118,497 173,119 14,509 18,473 7,655 12,805 452,209
Costs and other items
Crude oil and product purchases 19,765 10,035 102,027 138,024 8,237 13,069 3,931 8,108 303,196
Operating expenses, excl. depreciation and depletion (1) 11,344 10,515 8,387 9,162 4,620 4,693 2,079 2,297 53,097
Depreciation and depletion (includes impairments) 13,906 7,451 828 749 595 760 107 163 24,559
Interest expense 128 40 5 37 — ( 2 ) — 13 221
Other taxes and duties 179 2,097 3,240 19,205 79 174 9 184 25,167
Total costs and other deductions 45,322 30,138 114,487 167,177 13,531 18,694 6,126 10,765 406,240
Segment income (loss) before income taxes 6,167 25,524 4,010 5,942 978 ( 221 ) 1,529 2,040 45,969
Income tax expense (benefit) 1,104 8,753 792 1,097 75 ( 144 ) 327 362 12,366
Segment net income (loss) incl. noncontrolling interests 5,063 16,771 3,218 4,845 903 ( 77 ) 1,202 1,678 33,603
Net income (loss) attributable to noncontrolling interests — 480 226 414 — 26 2 21 1,169
Segment income (loss) 5,063 16,291 2,992 4,431 903 ( 103 ) 1,200 1,657 32,434
Reconciliation of consolidated revenues
Segment revenues and other income 452,209
Other revenues (2) 1,034
Elimination of intersegment revenues ( 121,005 )
Total consolidated revenues and other income 332,238
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss) 32,434
Corporate and Financing income (loss) ( 3,590 )
Net income (loss) attributable to ExxonMobil 28,844
(millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S.
As of December 31, 2025
Additions to property, plant, and equipment (3) 15,872 9,490 703 1,251 800 522 368 227 29,233
Investments in equity companies 5,491 19,429 460 1,048 2,946 2,616 — 775 32,765
Total assets 153,042 134,529 32,652 47,265 17,365 17,991 2,961 8,020 413,825
Reconciliation to Corporate Total Segment Total Corporate and Financing Corporate Total
Additions to property, plant, and equipment (3) 29,233 2,243 31,476
Investments in equity companies 32,765 ( 112 ) 32,653
Total assets 413,825 35,155 448,980
(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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(millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S.
Year ended December 31, 2024
Revenues and other income
Sales and other operating revenue 22,929 14,202 101,325 159,531 8,558 14,338 5,790 12,463 339,136
Income from equity affiliates ( 36 ) 5,649 140 ( 109 ) 166 615 — ( 26 ) 6,399
Intersegment revenue 24,633 41,809 23,626 26,034 7,329 3,893 2,462 573 130,359
Other income 890 670 295 192 5 7 22 116 2,197
Segment revenues and other income 48,416 62,330 125,386 185,648 16,058 18,853 8,274 13,126 478,091
Costs and other items
Crude oil and product purchases 18,325 10,388 110,205 153,811 8,510 12,621 4,160 8,753 326,773
Operating expenses, excl. depreciation and depletion (1) 9,822 10,695 8,034 8,924 4,781 4,419 1,931 2,316 50,922
Depreciation and depletion (includes impairments) 11,510 8,014 799 734 611 485 104 133 22,390
Interest expense 185 82 9 10 1 1 — 3 291
Other taxes and duties 334 2,750 3,421 19,699 68 78 7 185 26,542
Total costs and other deductions 40,176 31,929 122,468 183,178 13,971 17,604 6,202 11,390 426,918
Segment income (loss) before income taxes 8,240 30,401 2,918 2,470 2,087 1,249 2,072 1,736 51,173
Income tax expense (benefit) 1,814 10,622 631 164 460 262 494 243 14,690
Segment net income (loss) incl. noncontrolling interests 6,426 19,779 2,287 2,306 1,627 987 1,578 1,493 36,483
Net income (loss) attributable to noncontrolling interests — 815 188 372 — 37 2 17 1,431
Segment income (loss) 6,426 18,964 2,099 1,934 1,627 950 1,576 1,476 35,052
Reconciliation of consolidated revenues
Segment revenues and other income 478,091
Other revenues (2) 1,853
Elimination of intersegment revenues ( 130,359 )
Total consolidated revenues and other income 349,585
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss) 35,052
Corporate and Financing income (loss) ( 1,372 )
Net income (loss) attributable to ExxonMobil 33,680
(millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S.
As of December 31, 2024
Additions to property, plant, and equipment (3) 94,649 8,371 589 1,450 474 1,161 230 227 107,151
Investments in equity companies 4,884 21,396 444 915 3,016 2,649 — 814 34,118
Total assets 154,914 134,609 32,143 43,399 17,445 17,692 2,882 8,040 411,124
Reconciliation to Corporate Total Segment Total Corporate and Financing Corporate Total
Additions to property, plant, and equipment (3) 107,151 2,181 109,332
Investments in equity companies 34,118 ( 108 ) 34,010
Total assets 411,124 42,351 453,475
(1) Operating expenses, excl. depreciation and depletion includes the following GAAP line items, as reflected on the Income Statement: Production and manufacturing expenses; Selling, general and administrative expenses; Exploration expenses, including dry holes; and Non-service pension and postretirement benefit expense.
(2) Primarily Corporate and Financing Interest revenue of $ 1,600 million.
(3) Includes non-cash additions. See Note 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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(millions of dollars) Upstream Energy Products Chemical Products Specialty Products Segment Total
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S.
Year ended December 31, 2023
Revenues and other income
Sales and other operating revenue 9,500 16,074 103,868 164,515 7,951 14,314 6,044 12,363 334,629
Income from equity affiliates 63 5,550 140 131 126 761 — ( 25 ) 6,746
Intersegment revenue 20,971 38,982 23,481 28,258 7,991 3,643 2,570 555 126,451
Other income 631 466 183 87 6 12 19 139 1,543
Segment revenues and other income 31,165 61,072 127,672 192,991 16,074 18,730 8,633 13,032 469,369
Costs and other items
Crude oil and product purchases 9,945 11,279 107,796 152,487 8,824 13,096 4,718 8,955 317,100
Operating expenses, excl. depreciation and depletion (1) 6,696 10,960 7,851 9,434 4,560 4,643 1,822 2,238 48,204
Depreciation and depletion (includes impairments) 8,863 7,737 765 797 605 706 93 222 19,788
Interest expense 82 74 4 7 2 2 — 2 173
Other taxes and duties 361 2,684 3,421 22,226 61 78 6 174 29,011
Total costs and other deductions 25,947 32,734 119,837 184,951 14,052 18,525 6,639 11,591 414,276
Segment income (loss) before income taxes 5,218 28,338 7,835 8,040 2,022 205 1,994 1,441 55,093
Income tax expense (benefit) 1,016 10,593 1,543 1,492 396 158 458 235 15,891
Segment net income (loss) incl. noncontrolling interests 4,202 17,745 6,292 6,548 1,626 47 1,536 1,206 39,202
Net income (loss) attributable to noncontrolling interests — 639 169 529 — 36 — 28 1,401
Segment income (loss) 4,202 17,106 6,123 6,019 1,626 11 1,536 1,178 37,801
Reconciliation of consolidated revenues
Segment revenues and other income 469,369
Other revenues (2) 1,664
Elimination of intersegment revenues ( 126,451 )
Total consolidated revenues and other income 344,582
Reconciliation of income (loss) attributable to ExxonMobil
Total segment income (loss) 37,801
Corporate and Financing income (loss) ( 1,791 )
Net income (loss) attributable to ExxonMobil 36,010
(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) 2025 2024 2023
Revenue from contracts with customers 226,909 245,143 256,455
Revenue outside the scope of ASC 606 96,996 94,104 78,242
Total 323,905 339,247 334,697

Geographic
Sales and other operating revenue (millions of dollars) 2025 2024 2023
United States 137,639 138,657 127,374
Non-U.S. 186,266 200,590 207,323
Total 323,905 339,247 334,697
Significant non-U.S. revenue sources include: (1)
Canada 27,363 29,746 28,994
(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,
2025 2024 2023
United States 183,619 178,633 95,792
Non-U.S. 115,754 115,685 119,148
Total 299,373 294,318 214,940
Significant non-U.S. long-lived assets include:
Canada 29,973 28,761 31,682

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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) U.S. Non-U.S.
2025 2024 2025 2024 2025 2024
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate (percent) 5.50 5.70 5.00 4.60 5.50 5.80
Long-term rate of compensation increase (percent) 4.00 4.00 4.30 4.20 4.00 4.00
Change in benefit obligation
Benefit obligation at January 1 12,999 13,143 19,198 21,327 4,791 5,014
Service cost 517 499 324 338 75 81
Interest cost 677 671 842 823 262 250
Actuarial loss/(gain) (1) 218 ( 441 ) ( 1,231 ) ( 658 ) 55 ( 81 )
Benefits paid (2)(3) ( 1,104 ) ( 874 ) ( 1,273 ) ( 1,240 ) ( 449 ) ( 534 )
Foreign exchange rate changes — — 1,648 ( 1,274 ) 20 ( 40 )
Amendments, divestments and other (5)(6) ( 795 ) 1 ( 990 ) ( 118 ) 138 101
Benefit obligation at December 31 12,512 12,999 18,518 19,198 4,892 4,791
Accumulated benefit obligation at December 31 10,838 11,227 17,210 17,818 — —

 
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) U.S. Non-U.S.
2025 2024 2025 2024 2025 2024
Change in plan assets
Fair value at January 1 11,244 11,367 17,378 18,431 364 371
Actual return on plan assets 1,189 286 680 862 40 20
Foreign exchange rate changes — — 1,364 ( 1,051 ) — —
Company contribution 250 300 307 288 29 24
Benefits paid (4) ( 878 ) ( 709 ) ( 940 ) ( 931 ) ( 49 ) ( 51 )
Other (5)(6) ( 767 ) — ( 641 ) ( 221 ) — —
Fair value at December 31 11,038 11,244 18,148 17,378 384 364
(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) U.S. Non-U.S.
2025 2024 2025 2024
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans ( 81 ) ( 267 ) 2,879 1,679
Unfunded plans ( 1,393 ) ( 1,488 ) ( 3,249 ) ( 3,499 )
Total ( 1,474 ) ( 1,755 ) ( 370 ) ( 1,820 )

 
The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its Consolidated Balance Sheet and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
Pension Benefits Other Postretirement Benefits
(millions of dollars) U.S. Non-U.S.
2025 2024 2025 2024 2025 2024
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1) ( 1,474 ) ( 1,755 ) ( 370 ) ( 1,820 ) ( 4,508 ) ( 4,427 )
Amounts recorded in the Consolidated Balance Sheet consist of:
Other assets 3 2 3,175 2,399 — —
Current liabilities ( 199 ) ( 213 ) ( 208 ) ( 207 ) ( 276 ) ( 283 )
Postretirement benefits reserves ( 1,278 ) ( 1,544 ) ( 3,337 ) ( 4,012 ) ( 4,232 ) ( 4,144 )
Total recorded ( 1,474 ) ( 1,755 ) ( 370 ) ( 1,820 ) ( 4,508 ) ( 4,427 )
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain) 79 631 ( 532 ) 557 ( 1,291 ) ( 1,421 )
Prior service cost ( 222 ) ( 252 ) 447 420 ( 345 ) ( 405 )
Total recorded in accumulated other comprehensive income ( 143 ) 379 ( 85 ) 977 ( 1,636 ) ( 1,826 )
(1) Fair value of assets less benefit obligation shown on the preceding page.

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The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted-average of the target asset allocation percentages and the long-term return assumption for each asset class.
Pension Benefits Other Postretirement Benefits
(millions of dollars, except where stated otherwise) U.S. Non-U.S.
2025 2024 2023 2025 2024 2023 2025 2024 2023
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
Discount rate (percent) 5.70 5.30 5.60 4.60 4.30 4.90 5.80 5.30 5.60
Long-term rate of return on funded assets (percent) 6.00 6.80 5.20 4.70 5.50 4.20 5.30 6.00 4.70
Long-term rate of compensation increase (percent) 4.00 4.50 4.50 4.20 4.50 5.20 4.00 4.50 4.50
Components of net periodic benefit cost
Service cost 517 499 466 324 338 323 75 81 78
Interest cost 677 671 664 842 823 922 262 250 276
Expected return on plan assets ( 596 ) ( 724 ) ( 532 ) ( 838 ) ( 955 ) ( 688 ) ( 16 ) ( 20 ) ( 14 )
Amortization of actuarial loss/(gain) 73 83 85 37 97 108 ( 103 ) ( 103 ) ( 122 )
Amortization of prior service cost ( 31 ) ( 31 ) ( 29 ) 59 50 52 ( 62 ) ( 63 ) ( 42 )
Net pension enhancement and curtailment/settlement cost 75 27 29 22 16 5 ( 1 ) — —
Net periodic benefit cost 715 525 683 446 369 722 155 145 176
Changes in amounts recorded in accumulated other comprehensive income:
Net actuarial loss/(gain) ( 406 ) ( 3 ) ( 39 ) ( 1,073 ) ( 611 ) 602 32 ( 81 ) 154
Amortization of actuarial (loss)/gain ( 147 ) ( 110 ) ( 114 ) ( 38 ) ( 112 ) ( 108 ) 103 103 122
Prior service cost/(credit) — — ( 17 ) 19 81 153 — ( 8 ) ( 312 )
Amortization of prior service (cost)/credit 31 31 29 ( 59 ) ( 44 ) ( 52 ) 63 63 42
Foreign exchange rate changes — — — 89 ( 102 ) 46 ( 8 ) 9 ( 2 )
Total recorded in other comprehensive income ( 522 ) ( 82 ) ( 141 ) ( 1,062 ) ( 788 ) 641 190 86 4
Total recorded in net periodic benefit cost and other comprehensive income, before tax 193 443 542 ( 616 ) ( 419 ) 1,363 345 231 180

 
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) 2025 2024 2023
(Charge)/credit to other comprehensive income, before tax
U.S. pension 522 82 141
Non-U.S. pension 1,062 788 ( 641 )
Other postretirement benefits ( 190 ) ( 86 ) ( 4 )
Total (charge)/credit to other comprehensive income, before tax 1,394 784 ( 504 )
(Charge)/credit to income tax (see Note 5 ) ( 376 ) ( 208 ) 180
(Charge)/credit to investment in equity companies 29 24 16
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax 1,047 600 ( 308 )
Charge/(credit) to equity of noncontrolling interests ( 59 ) ( 120 ) 54
(Charge)/credit to other comprehensive income attributable to ExxonMobil 988 480 ( 254 )

 
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
U.S. — — — 2,018 2,018 — — — 1,659 1,659
Non-U.S. — — — 1,216 1,216 54 (1) — — 993 1,047
Private equity — — — 728 728 — — — 337 337
Debt securities
Corporate — 985 (2) — 4,238 5,223 — 54 (2) — 3,980 4,034
Government — 696 (2) — 990 1,686 99 (3) 169 (2) — 9,033 9,301
Asset-backed — — — 1 1 — 18 (2) — 149 167
Other — — — — — — — — 33 33
Real Estate — — — — — — — — 151 151
Cash — — — 141 141 11 9 (4) — 1,383 1,403
Other — 23 — — 23 — — — — —
Total at fair value — 1,704 — 9,332 11,036 164 250 — 17,718 18,132
Insurance contracts at contract value 2 16
Total plan assets 11,038 18,148
(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
U.S. 95 (5) — — — 95
Non-U.S. 41 (5) — — — 41
Debt securities
Corporate — 58 (6) — — 58
Government — 185 (6) — — 185
Asset-backed — 3 (6) — — 3
Cash — 2 — — 2
Total at fair value 136 248 — — 384
(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
U.S. — — — 2,263 2,263 — — — 2,865 2,865
Non-U.S. — — — 1,225 1,225 43 (1) — — 1,560 1,603
Private equity — — — 439 439 — — — 291 291
Debt securities
Corporate — 971 (2) — 4,498 5,469 — 49 (2) — 3,650 3,699
Government — 592 (2) — 1,126 1,718 77 (3) 141 (2) — 8,222 8,440
Asset-backed — — — 1 1 — 12 (2) — 180 192
Other — — — — — — — — 13 13
Real Estate — — — — — — — — 107 107
Cash — — — 113 113 78 6 (4) — 69 153
Other — 14 — — 14 — — — — —
Total at fair value — 1,577 — 9,665 11,242 198 208 — 16,957 17,363
Insurance contracts at contract value 2 15
Total plan assets 11,244 17,378
(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a level 2 input.

Other Postretirement
(millions of dollars) Fair Value Measurement at December 31, 2024, Using:
Level 1 Level 2 Level 3 Net Asset Value Total
Asset category:
Equity securities
U.S. 92 (5) — — — 92
Non-U.S. 36 (5) — — — 36
Debt securities
Corporate — 57 (6) — — 57
Government — 174 (6) — — 174
Asset-backed — 3 (6) — — 3
Cash — 2 — — 2
Total at fair value 128 236 — — 364
(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) U.S. Non-U.S.
2025 2024 2025 2024
For funded pension plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation — — 127 1,025
Fair value of plan assets — — 66 574
For funded pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation 11,107 11,501 1,137 1,982
Fair value of plan assets 11,025 11,232 840 1,261
For unfunded pension plans:
Projected benefit obligation 1,393 1,488 3,249 3,499
Accumulated benefit obligation 1,184 1,229 3,057 3,224

 
All other postretirement benefit plans are unfunded or underfunded.
Pension Benefits Other Postretirement Benefits
(millions of dollars) U.S. Non-U.S. Gross Medicare Subsidy Receipt
Contributions expected in 2026 — 306 — —
Benefit payments expected in:
2026 1,024 1,107 350 1
2027 1,017 1,121 347 1
2028 1,049 1,135 346 1
2029 1,053 1,149 346 1
2030 1,060 1,149 348 1
2031 - 2035 5,701 5,759 1,775 3

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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 ( 14,591 ) 1,321 ( 13,270 )
Current period change excluding amounts reclassified from accumulated other comprehensive income (1) 1,108 ( 305 ) 803
Amounts reclassified from accumulated other comprehensive income 427 51 478
Total change in accumulated other comprehensive income 1,535 ( 254 ) 1,281
Balance as of December 31, 2023 ( 13,056 ) 1,067 ( 11,989 )
Current period change excluding amounts reclassified from accumulated other comprehensive income (1) ( 3,110 ) 449 ( 2,661 )
Amounts reclassified from accumulated other comprehensive income — 31 31
Total change in accumulated other comprehensive income ( 3,110 ) 480 ( 2,630 )
Balance as of December 31, 2024 ( 16,166 ) 1,547 ( 14,619 )
Current period change excluding amounts reclassified from accumulated other comprehensive income (1) 2,360 952 3,312
Amounts reclassified from accumulated other comprehensive income 408 36 444
Total change in accumulated other comprehensive income 2,768 988 3,756
Balance as of December 31, 2025 ( 13,398 ) 2,535 ( 10,863 )
(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) 2025 2024 2023
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) ( 391 ) — ( 609 )
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense) ( 46 ) ( 70 ) ( 81 )

Income Tax (Expense)/Credit For Components of Other Comprehensive Income (millions of dollars) 2025 2024 2023
Foreign exchange translation adjustment 145 14 341
Postretirement benefits reserves adjustment (excluding amortization) ( 368 ) ( 181 ) 200
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs ( 8 ) ( 27 ) ( 20 )
Total ( 231 ) ( 194 ) 521

 
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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) 5,197 2,259 — 7,456 ( 6,261 ) ( 341 ) — 854
Advances to/receivables from equity companies (2)(6) — 1,935 3,938 5,873 — — 256 6,129
Other long-term financial assets (3) 1,536 — 1,800 3,336 — — 216 3,552
Liabilities
Derivative liabilities (4) 4,994 2,043 — 7,037 ( 6,261 ) ( 141 ) — 635
Long-term debt (5) 24,678 3,909 — 28,587 — — 3,248 31,835
Long-term obligations to equity companies (6) — — 542 542 — — — 542
Other long-term financial liabilities (7) — — 348 348 — — 16 364

December 31, 2024
Fair Value
(millions of dollars) Level 1 Level 2 Level 3 Total Gross Assets & Liabilities Effect of Counterparty Netting Effect of Collateral Netting Difference in Carrying Value and Fair Value Net Carrying Value
Assets
Derivative assets (1) 3,223 1,206 — 4,429 ( 3,913 ) ( 3 ) — 513
Advances to/receivables from equity companies (2)(6) — 2,466 4,167 6,633 — — 451 7,084
Other long-term financial assets (3) 1,468 — 1,504 2,972 — — 247 3,219
Liabilities
Derivative liabilities (4) 3,561 1,416 — 4,977 ( 3,913 ) ( 341 ) — 723
Long-term debt (5) 28,884 1,813 — 30,697 — — 3,935 34,632
Long-term obligations to equity companies (6) — — 1,393 1,393 — — ( 47 ) 1,346
Other long-term financial liabilities (7) — — 583 583 — — 57 640
(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,
2025 2024
Crude oil (barrels) 6 13
Petroleum products (barrels) ( 27 ) ( 32 )
Natural gas (MMBTUs) ( 449 ) ( 675 )

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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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 667 6,185 6,852
Total 667 6,185 6,852
(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) 2025 2024 2023
Total ExxonMobil Share Total ExxonMobil Share Total ExxonMobil Share
Total revenues 111,193 34,309 117,036 35,532 132,783 40,682
Income before income taxes 26,493 7,106 33,357 9,304 35,999 10,078
Income taxes 8,174 2,054 11,434 3,209 11,404 3,085
Income from equity affiliates 18,319 5,052 21,923 6,095 24,595 6,993
Current assets 46,577 16,738 50,779 18,286 53,081 18,713
Long-term assets 138,809 37,398 145,671 39,092 150,198 40,986
Total assets 185,386 54,136 196,450 57,378 203,279 59,699
Current liabilities 28,135 8,947 26,786 8,699 30,721 9,652
Long-term liabilities 47,301 14,361 55,218 16,484 57,237 17,059
Net assets 109,950 30,828 114,446 32,195 115,321 32,988

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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 7
BEB Erdgas und Erdoel GmbH & Co. KG 50
Caspian Pipeline Consortium 8
Coral FLNG S.A. 25
Cross Timbers Energy LLC 50
GasTerra B.V. 25
Golden Pass LNG Terminal LLC 30
Golden Pass Pipeline LLC 30
Marine Well Containment Company LLC 13
Mozambique Rovuma Venture S.p.A. 36
Nederlandse Aardolie Maatschappij B.V. 50
Papua New Guinea Liquefied Natural Gas Global Company LDC 33
Permian Highway Pipeline LLC 17
QatarEnergy LNG N (2) 24
QatarEnergy LNG NFE (3) 25
QatarEnergy LNG S (2) 31
QatarEnergy LNG S (3) 30
South Hook LNG Terminal Company Limited 24
Tengizchevroil LLP 25
Energy Products, Chemical Products, and/or Specialty Products
Al-Jubail Petrochemical Company 50
Alberta Products Pipe Line Ltd. 45
Fujian Refining & Petrochemical Co. Ltd. 25
Gulf Coast Growth Ventures LLC 50
Infineum USA L.P. 50
Permian Express Partners LLC 12
Saudi Aramco Mobil Refinery Company Ltd. 50
Saudi Yanbu Petrochemical Co. 50

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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 436,018 228,235 423,038 226,021
Energy Products 60,261 29,547 58,259 28,349
Chemical Products 39,594 20,053 39,224 19,973
Specialty Products 8,820 4,333 9,559 4,229
Other 25,366 17,205 23,823 15,746
Total 570,059 299,373 553,903 294,318

 
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) 2025 2024 2023
Balance at January 1 12,032 12,989 10,491
Accretion expense and other provisions 623 709 734
Reduction due to property sales ( 927 ) ( 1,445 ) ( 288 )
Payments made ( 1,289 ) ( 1,191 ) ( 693 )
Liabilities incurred 539 728 985
Foreign currency translation 386 ( 447 ) 124
Revisions 1,154 689 1,636
Balance at December 31 12,518 12,032 12,989

 
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 35,744 35,282
Other, less reserves of $ 170 million and $ 314 million 8,818 8,399
Total 44,562 43,681
Notes and loans payable
Bank loans 3 63
Commercial paper 3,059 —
Long-term debt due within one year 6,234 4,892
Total 9,296 4,955
Accounts payable and accrued liabilities
Trade payables 36,049 36,145
Payables to equity companies 8,694 10,378
Accrued taxes other than income taxes 3,549 3,577
Other 12,619 11,197
Total 60,911 61,297

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 32,653 34,010
Advances, net of allowances of $ 33 million and $ 40 million 6,130 7,084
Total equity method company investments and advances 38,783 41,094
Equity securities carried at fair value and other investments at adjusted cost basis 271 343
Long-term receivables and miscellaneous, net of reserves of $ 2,500 million and $ 2,433 million 6,263 5,763
Total 45,317 47,200

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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 — 2,500
2.275 % notes due 2026 — 1,000
3.294 % notes due 2027 1,000 1,000
2.440 % notes due 2029 1,250 1,250
3.482 % notes due 2030 2,032 1,992
2.610 % notes due 2030 2,016 2,000
2.995 % notes due 2039 750 750
4.227 % notes due 2040 2,043 2,076
3.567 % notes due 2045 986 1,000
4.114 % notes due 2046 2,497 2,500
3.095 % notes due 2049 1,500 1,500
4.327 % notes due 2050 2,750 2,750
3.452 % notes due 2051 2,750 2,750
Exxon Mobil Corporation - Euro-denominated
0.524 % notes due 2028 1,175 1,039
0.835 % notes due 2032 1,175 1,039
1.408 % notes due 2039 1,175 1,039
XTO Energy Inc. (4)
6.100 % senior notes due 2036 186 187
6.750 % senior notes due 2037 282 284
6.375 % senior notes due 2038 219 221
Pioneer Natural Resources Company (5)
1.125 % senior notes due 2026 — 718
5.100 % senior notes due 2026 — 1,097
7.200 % senior notes due 2028 247 250
1.900 % senior notes due 2030 958 931
2.150 % senior notes due 2031 869 846
Parsley Energy LLC (6)
4.125 % senior notes due 2028 133 131
Industrial revenue bonds due 2026-2051 2.540 % 2,005 2,032
Finance leases & other obligations 4.668 % 6,313 3,951
Debt issuance costs ( 70 ) ( 78 )
Total long-term debt 34,241 36,755
(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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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
2025 2024 2023 2025 2024 2023
Operating lease cost 2,450 2,296 1,976
Short-term and other (net of sublease rental income) 1,490 2,047 1,563
Amortization of right of use assets 161 140 107
Interest on lease liabilities 167 149 140
Total (1) 3,940 4,343 3,539 328 289 247
(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 7,224 7,123
Included in Property, plant, and equipment - net 3,284 2,888
Total right of use assets 7,224 7,123 3,284 2,888
Lease liability due within one year
Included in Accounts payable and accrued liabilities 1,942 1,852 7 6
Included in Notes and loans payable 137 117
Long-term lease liability
Included in Other long-term obligations 4,892 4,626
Included in Long-term debt 2,406 2,123
Included in Long-term obligations to equity companies 109 115
Total lease liability (2) 6,834 6,478 2,659 2,361
Weighted-average remaining lease term (years) 8 7 17 18
Weighted-average discount rate (percent) 4.7 % 4.9 % 8.1 % 6.4 %
(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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Maturity Analysis of Lease Liabilities (millions of dollars) Operating Leases Finance Leases
December 31, 2025
2026 2,189 362
2027 1,609 351
2028 1,042 348
2029 502 341
2030 402 335
2031 and beyond 2,237 3,128
Total lease payments 7,981 4,865
Discount to present value ( 1,147 ) ( 2,206 )
Total lease liability 6,834 2,659

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
2025 2024 2023 2025 2024 2023
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities 1,522 1,301 1,135 20 20 20
Cash flows from investing activities 868 837 758
Cash flows from financing activities 140 121 86
Noncash right of use assets recorded for lease liabilities
In exchange for lease liabilities during the period 2,310 2,074 2,161 403 109 529

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 7,976 6,483
Petroleum products 6,889 6,017
Chemical products (1) 4,261 4,142
Gas/other 3,853 2,802
Total 22,979 19,444
(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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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) 2025 2024 2023
U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total
Income tax expense (benefit) Federal and non-U.S.
Current 143 10,271 10,414 2,061 11,940 14,001 1,987 12,111 14,098
Deferred - net 372 596 968 ( 318 ) ( 512 ) ( 830 ) 463 481 944
U.S. tax on non-U.S. operations 175 — 175 241 — 241 315 — 315
Total federal and non-U.S. 690 10,867 11,557 1,984 11,428 13,412 2,765 12,592 15,357
State ( 53 ) — ( 53 ) 398 — 398 72 — 72
Total income tax expense (benefit) 637 10,867 11,504 2,382 11,428 13,810 2,837 12,592 15,429
All other taxes and duties
Other taxes and duties 3,521 21,646 25,167 3,849 22,439 26,288 3,871 25,140 29,011
Included in production and manufacturing expenses 2,707 628 3,335 2,510 652 3,162 1,961 726 2,687
Included in SG&A expenses 155 273 428 179 265 444 183 310 493
Total other taxes and duties 6,383 22,547 28,930 6,538 23,356 29,894 6,015 26,176 32,191
Total 7,020 33,414 40,434 8,920 34,784 43,704 8,852 38,768 47,620

 
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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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) 2025
Income (loss) before income taxes
United States 11,000
Non-U.S. 30,268
Total 41,268
U.S. federal statutory theoretical tax 8,666 21 %
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax 4,212 10 %
United Arab Emirates rate differential 3,405 8 %
Qatar ( 552 ) ( 1 ) %
Effect of equity method of accounting ( 620 ) ( 2 ) %
Other 68 0 %
All other countries 1,359 3 %
State taxes, net of federal tax benefit ( 76 ) 0 %
Other ( 1,298 ) ( 3 ) %
Total income tax expense (credit) 11,504 28 %
Income tax expense (credit) 11,504
ExxonMobil share of equity company income taxes 2,046
Total income tax expense (credit) 13,550
Net income (loss) including noncontrolling interests 29,764
Total income (loss) before taxes 43,314
Effective income tax rate 31 %

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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) 2024 2023
Income (loss) before income taxes
United States 12,258 14,786
Non-U.S. 36,615 37,997
Total 48,873 52,783
Theoretical tax 10,263 11,084
Effect of equity method of accounting ( 1,301 ) ( 1,341 )
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax 4,986 5,888
State taxes, net of federal tax benefit 314 57
Other ( 452 ) ( 259 )
Total income tax expense (credit) 13,810 15,429
Income tax expense (credit) 13,810 15,429
ExxonMobil share of equity company income taxes 3,197 3,058
Total income tax expense (credit) 17,007 18,487
Net income (loss) including noncontrolling interests 35,063 37,354
Total income (loss) before taxes 52,070 55,841
Effective income tax rate 33 % 33 %

Income taxes paid for 2025 U.S. and non-U.S. are shown in the table below:
(millions of dollars) 2025
Income taxes paid
U.S. Federal 944
U.S. State 170
U.S. 1,114
Canada 1,207
Guyana 1,100
United Arab Emirates 5,000
All Other Countries 3,142
Non-U.S. 10,449
Total income taxes paid 11,563

Cash income taxes paid for 2024 and 2023 were $
13,293
million and $
15,473
million respectively.
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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) 2025 2024
Property, plant, and equipment 41,427 40,881
Other liabilities 8,358 8,113
Total deferred tax liabilities 49,785 48,994
Pension and other postretirement benefits ( 972 ) ( 1,365 )
Asset retirement obligations ( 3,249 ) ( 3,156 )
Tax loss carryforwards ( 4,740 ) ( 4,575 )
Other assets ( 7,016 ) ( 7,308 )
Total deferred tax assets ( 15,977 ) ( 16,404 )
Asset valuation allowances 2,649 2,516
Net deferred tax liabilities 36,457 35,106

 
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) 2025 2024
Other assets, including intangibles, net ( 3,759 ) ( 3,936 )
Deferred income tax liabilities 40,216 39,042
Net deferred tax liabilities 36,457 35,106

 
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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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) 2025 2024 2023
Balance at January 1 4,035 3,935 3,398
Additions based on current year's tax positions 206 376 350
Additions for prior years' tax positions 454 103 400
Reductions for prior years' tax positions ( 377 ) ( 293 ) ( 38 )
Reductions due to lapse of the statute of limitations ( 4 ) ( 17 ) ( 25 )
Settlements with tax authorities ( 150 ) ( 13 ) ( 153 )
Foreign exchange effects/other ( 33 ) ( 56 ) 3
Balance at December 31 4,131 4,035 3,935

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 2001 — 2025
Kazakhstan 2020 — 2025
Papua New Guinea 2008 — 2025
Qatar 2020 — 2025
United Arab Emirates 2024 — 2025
United States 2010 — 2025

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) 2025 2024 2023
Balance beginning at January 1 3,600 3,559 3,512
Additions pending the determination of proved reserves 250 453 200
Charged to expense ( 432 ) ( 69 ) ( 95 )
Reclassifications to wells, facilities and equipment based on the determination of proved reserves ( 141 ) ( 292 ) ( 142 )
Divestments/Other 9 ( 51 ) 84
Ending balance at December 31 3,286 3,600 3,559
Ending balance attributed to equity companies included above 225 225 306

 
Period-end capitalized suspended exploratory well costs (millions of dollars) 2025 2024 2023
Capitalized for a period of one year or less 250 453 200
Capitalized for a period of between one and five years 933 583 1,030
Capitalized for a period of between five and ten years 1,144 1,544 1,411
Capitalized for a period of greater than ten years 959 1,020 918
Capitalized for a period greater than one year - subtotal 3,036 3,147 3,359
Total 3,286 3,600 3,559

 
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.
2025 2024 2023
Number of projects that only have exploratory well costs capitalized for a period of one year or less 1 5 —
Number of projects that have exploratory well costs capitalized for a period greater than one year 25 24 31
Total 26 29 31

 
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) 2025 2024 2023
Cash interest paid
Included in cash flows from operating activities 218 624 584
Capitalized, included in cash flows from investing activities 1,534 1,276 1,152
Total cash interest paid 1,752 1,900 1,736

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 2025
Shares (thousands) Weighted-Average Grant-Date Fair Value per Share (dollars)
Issued and outstanding at January 1 39,595 85.29
Awards issued in 2025 10,327 118.72
Vested ( 8,716 ) 90.54
Forfeited ( 552 ) 100.77
Issued and outstanding at December 31 40,654 92.45

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 2025 2024 2023
Grant price (dollars) 115.02 118.57 103.16
Value at date of grant: (millions of dollars)
Units settled in stock 1,031 1,193 900
Units settled in cash 108 129 101
Total value 1,139 1,322 1,001

 
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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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) 3
Other non-current assets 1
Property, plant, & equipment (2) 84
Total identifiable assets acquired 88
Current liabilities (1) 3
Long-term debt (3) 5
Deferred income tax liabilities (4) 16
Other non-current liabilities 2
Total liabilities assumed 26
Net identifiable assets acquired 62
Goodwill (5) 1
Net assets 63
(1) Current assets and current liabilities consist primarily of accounts receivable and payable, with their respective fair values approximating historical values given their short-term duration, expectation of insignificant bad debt expense, and our credit rating.
(2) Property, plant, and equipment, of which a significant portion relates to crude oil and natural gas properties, was 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) 450 1,327
1.125 % Senior Notes due January 2026 750 699
5.100 % Senior Notes due March 2026 1,100 1,096
7.200 % Senior Notes due January 2028 241 252
4.125 % Senior Notes due February 2028 138 130
1.900 % Senior Notes due August 2030 1,100 914
2.150 % Senior Notes due January 2031 1,000 832
(1) In June 2024, the Corporation redeemed in full all of the Convertible Senior Notes assumed from Pioneer for an amount consistent with the acquisition date fair value.

Actual and Pro Forma Impact of Merger
The following table presents revenues and earnings included in the Consolidated Statement of Income for Pioneer since the acquisition date (May 3, 2024) through December 31, 2024:
(millions of dollars) Twelve Months Ended December 31, 2024
Sales and other operating revenues 17,008
Net income (loss) attributable to ExxonMobil 1,710

The following table presents unaudited pro forma information for the Corporation as if the merger with Pioneer had occurred at the beginning of January 1, 2023:
Unaudited (millions of dollars) Twelve Months Ended December 31,
2024 2023
Sales and other operating revenues 347,406 358,014
Net income (loss) attributable to ExxonMobil 34,476 39,211

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2023. In addition, the unaudited pro forma consolidated results reflect pro forma adjustments primarily related to conforming Pioneer's accounting policies to ExxonMobil, additional depreciation expense related to the fair value adjustment of the acquired property, plant, and equipment, our capital structure, Pioneer's transaction-related costs, and applicable income tax impacts of the pro forma adjustments.
Our transaction costs to effect the acquisition were immaterial.
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
2025
Consolidated Subsidiaries
Sales to third parties 14,798 5,699 991 159 2,374 3,693 27,714
Transfers 13,696 11,866 49 3,233 9,821 501 39,166
Revenue 28,494 17,565 1,040 3,392 12,195 4,194 66,880
Production costs excluding taxes 8,397 4,793 450 1,053 1,192 488 16,373
Exploration expenses 26 354 97 127 311 92 1,007
Depreciation and depletion 13,538 3,367 331 802 1,505 707 20,250
Taxes other than income 2,101 96 50 88 1,780 279 4,394
Related income tax 880 1,406 64 505 5,631 594 9,080
Results of producing activities for consolidated subsidiaries 3,552 7,549 48 817 1,776 2,034 15,776
Equity Companies
Sales to third parties 68 — 321 249 12,734 — 13,372
Transfers — — 9 — 28 — 37
Revenue 68 — 330 249 12,762 — 13,409
Production costs excluding taxes 64 — 486 32 670 — 1,252
Exploration expenses — — 1 — — — 1
Depreciation and depletion 16 — 41 39 2,051 — 2,147
Taxes other than income 6 — 9 — 4,406 — 4,421
Related income tax — — (92) 52 1,953 — 1,913
Results of producing activities for equity companies (18) — (115) 126 3,682 — 3,675
Total results of operations 3,534 7,549 (67) 943 5,458 2,034 19,451

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Results of Operations (millions of dollars) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total
2024
Consolidated Subsidiaries
Sales to third parties 13,036 5,774 986 425 2,473 3,790 26,484
Transfers 13,745 13,140 43 5,764 10,825 817 44,334
Revenue 26,781 18,914 1,029 6,189 13,298 4,607 70,818
Production costs excluding taxes 6,869 4,745 406 1,723 1,163 610 15,516
Exploration expenses 43 485 46 213 31 8 826
Depreciation and depletion 11,114 3,343 94 1,436 1,390 852 18,229
Taxes other than income 2,163 115 31 479 1,987 370 5,145
Related income tax 1,502 2,025 202 605 6,562 805 11,701
Results of producing activities for consolidated subsidiaries 5,090 8,201 250 1,733 2,165 1,962 19,401
Equity Companies
Sales to third parties 69 — 361 191 13,054 — 13,675
Transfers — — 15 — 142 — 157
Revenue 69 — 376 191 13,196 — 13,832
Production costs excluding taxes 58 — 422 50 659 — 1,189
Exploration expenses — — 2 — — — 2
Depreciation and depletion 239 — 36 35 781 — 1,091
Taxes other than income 6 — 10 — 4,469 — 4,485
Related income tax — — (48) 24 2,495 — 2,471
Results of producing activities for equity companies (234) — (46) 82 4,792 — 4,594
Total results of operations 4,856 8,201 204 1,815 6,957 1,962 23,995
2023
Consolidated Subsidiaries
Sales to third parties 5,098 4,027 1,345 298 2,490 4,588 17,846
Transfers 13,378 11,474 47 6,355 10,779 600 42,633
Revenue 18,476 15,501 1,392 6,653 13,269 5,188 60,479
Production costs excluding taxes 4,164 4,943 623 1,710 1,146 511 13,097
Exploration expenses 44 505 25 124 18 35 751
Depreciation and depletion 8,479 2,866 96 1,561 1,519 755 15,276
Taxes other than income 1,701 117 48 516 1,936 358 4,676
Related income tax 703 1,196 315 1,299 6,498 1,078 11,089
Results of producing activities for consolidated subsidiaries 3,385 5,874 285 1,443 2,152 2,451 15,590
Equity Companies
Sales to third parties 182 — 1,211 214 14,653 — 16,260
Transfers 83 — 29 — 232 — 344
Revenue 265 — 1,240 214 14,885 — 16,604
Production costs excluding taxes 239 — 419 39 714 — 1,411
Exploration expenses — — — — — — —
Depreciation and depletion 58 — 27 42 605 — 732
Taxes other than income 12 — 27 — 5,049 — 5,088
Related income tax — — 202 30 2,904 — 3,136
Results of producing activities for equity companies (44) — 565 103 5,613 — 6,237
Total results of operations 3,341 5,874 850 1,546 7,765 2,451 21,827

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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 33,548 3,187 33 694 2,962 688 41,112
– Unproved 43,177 1,950 42 59 5 2,659 47,892
Total property costs 76,725 5,137 75 753 2,967 3,347 89,004
Producing assets 132,738 60,734 13,537 35,493 46,725 16,585 305,812
Incomplete construction 5,867 13,015 239 1,442 1,482 2,479 24,524
Total capitalized costs 215,330 78,886 13,851 37,688 51,174 22,411 419,340
Accumulated depreciation and depletion 76,273 31,036 13,165 33,603 34,165 11,915 200,157
Net capitalized costs for consolidated subsidiaries 139,057 47,850 686 4,085 17,009 10,496 219,183
Equity Companies
Property (acreage) costs – Proved — — 1 309 — — 310
– Unproved — — — 3,111 — — 3,111
Total property costs — — 1 3,420 — — 3,421
Producing assets 1,390 — 4,225 402 21,842 — 27,859
Incomplete construction 3 — 24 466 2,225 — 2,718
Total capitalized costs 1,393 — 4,250 4,288 24,067 — 33,998
Accumulated depreciation and depletion 1,081 — 4,000 113 9,886 — 15,080
Net capitalized costs for equity companies 312 — 250 4,175 14,181 — 18,918
As of December 31, 2024
Consolidated Subsidiaries
Property (acreage) costs – Proved 28,143 3,238 8 693 2,990 654 35,726
– Unproved 49,903 2,367 42 108 5 2,656 55,081
Total property costs 78,046 5,605 50 801 2,995 3,310 90,807
Producing assets 131,125 50,905 12,304 34,991 45,482 15,317 290,124
Incomplete construction 6,685 12,854 196 1,317 2,269 2,078 25,399
Total capitalized costs 215,856 69,364 12,550 37,109 50,746 20,705 406,330
Accumulated depreciation and depletion 74,303 27,479 11,953 32,837 32,822 10,534 189,928
Net capitalized costs for consolidated subsidiaries 141,553 41,885 597 4,272 17,924 10,171 216,402
Equity Companies
Property (acreage) costs – Proved — — 3 309 — — 312
– Unproved — — — 3,111 — — 3,111
Total property costs — — 3 3,420 — — 3,423
Producing assets 1,360 — 5,222 402 19,215 — 26,199
Incomplete construction 2 — 15 453 5,091 — 5,561
Total capitalized costs 1,362 — 5,240 4,275 24,306 — 35,183
Accumulated depreciation and depletion 1,046 — 4,935 76 8,564 — 14,621
Net capitalized costs for equity companies 316 — 305 4,199 15,742 — 20,562

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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 1,177 — — — — — 1,177
– Unproved 2,591 — — — — — 2,591
Exploration costs 66 1,304 80 102 12 54 1,618
Development costs 12,463 7,310 238 634 967 823 22,435
Total costs incurred for consolidated subsidiaries 16,297 8,614 318 736 979 877 27,821
Equity Companies
Property acquisition costs – Proved — — — — — — —
– Unproved — — — — — — —
Exploration costs — — 1 — — — 1
Development costs 9 — 21 15 769 — 814
Total costs incurred for equity companies 9 — 22 15 769 — 815
During 2024
Consolidated Subsidiaries
Property acquisition costs – Proved 39,271 — — 1 — — 39,272
– Unproved 45,196 — 5 — — — 45,201
Exploration costs 55 838 63 268 30 8 1,262
Development costs 10,903 5,839 113 910 750 844 19,359
Total costs incurred for consolidated subsidiaries 95,425 6,677 181 1,179 780 852 105,094
Equity Companies
Property acquisition costs – Proved — — — — — — —
– Unproved — — — — — — —
Exploration costs — — 2 — — — 2
Development costs 3 — 20 18 1,091 — 1,132
Total costs incurred for equity companies 3 — 22 18 1,091 — 1,134
During 2023
Consolidated Subsidiaries
Property acquisition costs – Proved 2,456 — — 2 — — 2,458
– Unproved 171 — — 6 — — 177
Exploration costs 54 693 23 117 18 35 940
Development costs 8,978 5,914 55 562 822 1,046 17,377
Total costs incurred for consolidated subsidiaries 11,659 6,607 78 687 840 1,081 20,952
Equity Companies
Property acquisition costs – Proved — — — — — — —
– Unproved — — — — — — —
Exploration costs — — — — — — —
Development costs 10 — 5 7 1,488 — 1,510
Total costs incurred for equity companies 10 — 5 7 1,488 — 1,510

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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 2,204 945 5 271 2,794 66 6,285 1,176 2,420 353 10,234
Revisions (398) 32 — 31 30 3 (302) (110) 123 26 (263)
Improved recovery — — — — — — — — — — —
Purchases 156 — — — — — 156 2 — — 158
Sales (12) — — — (4) — (16) (5) — — (21)
Extensions/discoveries 355 105 — — — — 460 272 — — 732
Production (203) (88) (1) (78) (153) (8) (531) (99) (129) (25) (784)
December 31, 2023 2,102 994 4 224 2,667 61 6,052 1,236 2,414 354 10,056
Attributable to noncontrolling interests 1 551 108
Proportional interest in proved reserves of equity companies
January 1, 2023 119 — 2 5 756 — 882 355 — — 1,237
Revisions — — 1 — 103 — 104 1 — — 105
Improved recovery — — — — — — — — — — —
Purchases — — — — — — — — — — —
Sales (108) — — — — — (108) (1) — — (109)
Extensions/discoveries — — — — — — — — — — —
Production (4) — — — (79) — (83) (22) — — (105)
December 31, 2023 7 — 3 5 780 — 795 333 — — 1,128
Total liquids proved reserves at December 31, 2023 2,109 994 7 229 3,447 61 6,847 1,569 2,414 354 11,184
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2024 2,102 994 4 224 2,667 61 6,052 1,236 2,414 354 10,056
Revisions (176) 116 — 62 603 1 606 (128) 152 (35) 595
Improved recovery — — — — — — — — — — —
Purchases 877 — — — — — 877 730 — — 1,607
Sales (18) (4) — (45) (7) — (74) (15) — — (89)
Extensions/discoveries 804 138 — 25 — — 967 489 — — 1,456
Production (316) (126) (1) (75) (154) (7) (679) (148) (137) (23) (987)
December 31, 2024 3,273 1,118 3 191 3,109 55 7,749 2,164 2,429 296 12,638
Attributable to noncontrolling interests — 552 90
Proportional interest in proved reserves of equity companies
January 1, 2024 7 — 3 5 780 — 795 333 — — 1,128
Revisions — — — 2 19 — 21 3 — — 24
Improved recovery — — — — — — — — — — —
Purchases — — — — — — — — — — —
Sales — — — — — — — — — — —
Extensions/discoveries — — — — — — — — — — —
Production (1) — (1) — (75) — (77) (22) — — (99)
December 31, 2024 6 — 2 7 724 — 739 314 — — 1,053
Total liquids proved reserves at December 31, 2024 3,279 1,118 5 198 3,833 55 8,488 2,478 2,429 296 13,691

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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 3,273 1,118 3 191 3,109 55 7,749 2,164 2,429 296 12,638
Revisions (652) 124 1 78 13 6 (430) (373) 42 17 (744)
Improved recovery — — — — — — — — — — —
Purchases 38 — — — — — 38 41 — — 79
Sales (72) — — — — — (72) (12) — — (84)
Extensions/discoveries 890 92 — — — 6 988 513 — — 1,501
Production (367) (139) (1) (52) (162) (7) (728) (194) (141) (25) (1,088)
December 31, 2025 3,110 1,195 3 217 2,960 60 7,545 2,139 2,330 288 12,302
Attributable to noncontrolling interests — 529 88
Proportional interest in proved reserves of equity companies
January 1, 2025 6 — 2 7 724 — 739 314 — — 1,053
Revisions — — 3 — (2) — 1 7 — — 8
Improved recovery — — — — — — — — — — —
Purchases — — — — — — — — — — —
Sales — — — — — — — — — — —
Extensions/discoveries — — — — — — — — — — —
Production (1) — — — (97) — (98) (23) — — (121)
December 31, 2025 5 — 5 7 625 — 642 298 — — 940
Total liquids proved reserves at December 31, 2025 3,115 1,195 8 224 3,585 60 8,187 2,437 2,330 288 13,242

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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 1,735 433 4 217 1,996 45 4,430 2,307 242 6,979
Equity companies 11 — 3 5 438 — 457 — — 457
Proved undeveloped reserves
Consolidated subsidiaries 1,498 561 — 20 751 28 2,858 107 112 3,077
Equity companies — — — — 671 — 671 — — 671
Total liquids proved reserves at December 31, 2023 3,244 994 7 242 3,856 73 8,416 2,414 354 11,184
As of December 31, 2024
Proved developed reserves
Consolidated subsidiaries 3,053 473 3 153 1,969 40 5,691 2,308 190 8,189
Equity companies 9 — 2 7 569 — 587 — — 587
Proved undeveloped reserves
Consolidated subsidiaries 2,308 646 — 38 1,208 22 4,222 121 106 4,449
Equity companies — — — — 466 — 466 — — 466
Total liquids proved reserves at December 31, 2024 5,370 1,119 5 198 4,212 62 10,966 2,429 296 13,691
As of December 31, 2025
Proved developed reserves
Consolidated subsidiaries 2,627 587 3 185 1,915 38 5,355 2,230 288 7,873
Equity companies 8 — 2 7 596 — 613 — — 613
Proved undeveloped reserves
Consolidated subsidiaries 2,546 609 — 32 1,112 30 4,329 100 — 4,429
Equity companies — — 3 — 324 — 327 — — 327
Total liquids proved reserves at December 31, 2025 5,181 1,196 8 224 3,947 68 10,624 (1) 2,330 288 13,242
(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 13,645 708 413 312 3,061 6,008 24,147 14,258
Revisions (1,945) (201) (3) (49) 121 339 (1,738) (553)
Improved recovery — — — — — — — —
Purchases 7 — — — — — 7 159
Sales (417) (1) — — (9) — (427) (92)
Extensions/discoveries 1,930 67 — — — — 1,997 1,065
Production (957) (53) (103) (43) (379) (489) (2,024) (1,121)
December 31, 2023 12,263 520 307 220 2,794 5,858 21,962 13,716
Attributable to noncontrolling interests 26
Proportional interest in proved reserves of equity companies
January 1, 2023 127 — 380 663 12,309 — 13,479 3,484
Revisions (27) — 18 157 (32) — 116 124
Improved recovery — — — — — — — —
Purchases — — — — — — — —
Sales (35) — — — — — (35) (115)
Extensions/discoveries — — — — — — — —
Production (8) — (54) (40) (956) — (1,058) (281)
December 31, 2023 57 — 344 780 11,321 — 12,502 3,212
Total proved reserves at December 31, 2023 12,320 520 651 1,000 14,115 5,858 34,464 16,928
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2024 12,263 520 307 220 2,794 5,858 21,962 13,716
Revisions (911) 22 198 24 124 97 (446) 521
Improved recovery — — — — — — — —
Purchases 4,044 — — — — — 4,044 2,281
Sales (83) (10) — (105) (5) — (203) (123)
Extensions/discoveries 2,683 68 — 2 — 1 2,754 1,915
Production (1,153) (59) (99) (46) (373) (477) (2,207) (1,355)
December 31, 2024 16,843 541 406 95 2,540 5,479 25,904 16,955
Attributable to noncontrolling interests 20
Proportional interest in proved reserves of equity companies
January 1, 2024 57 — 344 780 11,321 — 12,502 3,212
Revisions (3) — 9 80 49 — 135 46
Improved recovery — — — — — — — —
Purchases — — — — — — — —
Sales — — — — — — — —
Extensions/discoveries — — — — — — — —
Production (7) — (37) (44) (904) — (992) (264)
December 31, 2024 47 — 316 816 10,466 — 11,645 2,994
Total proved reserves at December 31, 2024 16,890 541 722 911 13,006 5,479 37,549 19,949
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.

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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 16,843 541 406 95 2,540 5,479 25,904 16,955
Revisions (1,482) 21 21 34 68 228 (1,110) (929)
Improved recovery — — — — — — — —
Purchases 234 — — — — — 234 118
Sales (248) (28) — — (14) — (290) (132)
Extensions/discoveries 2,769 26 — — — 485 3,280 2,048
Production (1,329) (33) (89) (16) (395) (482) (2,344) (1,478)
December 31, 2025 16,787 527 338 113 2,199 5,710 25,674 16,582
Attributable to noncontrolling interests 15
Proportional interest in proved reserves of equity companies
January 1, 2025 47 — 316 816 10,466 — 11,645 2,994
Revisions 7 — (3) 4 80 — 88 23
Improved recovery — — — — — — — —
Purchases — — — — — — — —
Sales — — (24) — — — (24) (4)
Extensions/discoveries — — — — — — — —
Production (6) — (26) (45) (898) — (975) (284)
December 31, 2025 48 — 263 775 9,648 — 10,734 2,729
Total proved reserves at December 31, 2025 16,835 527 601 888 11,847 5,710 36,408 19,311
(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 8,138 329 307 220 1,935 3,163 14,092 9,327
Equity companies 57 — 290 780 4,223 — 5,350 1,349
Proved undeveloped reserves
Consolidated subsidiaries 4,125 191 — — 859 2,695 7,870 4,389
Equity companies — — 54 — 7,098 — 7,152 1,863
Total proved reserves at December 31, 2023 12,320 520 651 1,000 14,115 5,858 34,464 16,928
As of December 31, 2024
Proved developed reserves
Consolidated subsidiaries 11,671 296 406 93 1,900 3,204 17,570 11,118
Equity companies 47 — 262 816 4,242 — 5,367 1,481
Proved undeveloped reserves
Consolidated subsidiaries 5,172 245 — 2 640 2,275 8,334 5,838
Equity companies — — 54 — 6,224 — 6,278 1,512
Total proved reserves at December 31, 2024 16,890 541 722 911 13,006 5,479 37,549 19,949
As of December 31, 2025
Proved developed reserves
Consolidated subsidiaries 11,206 356 338 111 2,010 3,057 17,078 10,722
Equity companies 48 — 207 775 4,782 — 5,812 1,582
Proved undeveloped reserves
Consolidated subsidiaries 5,581 171 — 2 189 2,653 8,596 5,860
Equity companies — — 56 — 4,866 — 4,922 1,147
Total proved reserves at December 31, 2025 16,835 527 601 888 11,847 5,710 36,408 19,311
(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 213,623 227,365 3,918 19,282 221,822 63,204 749,214
Future production costs 68,753 113,875 1,611 5,025 52,672 13,971 255,907
Future development costs 37,784 38,436 1,881 4,466 11,926 6,393 100,886
Future income tax expenses 14,270 15,973 509 4,337 121,751 12,119 168,959
Future net cash flows 92,816 59,081 (83) 5,454 35,473 30,721 223,462
Effect of discounting net cash flows at 10% 49,199 23,471 (762) 402 18,537 16,215 107,062
Discounted future net cash flows 43,617 35,610 679 5,052 16,936 14,506 116,400
Equity Companies
Future cash inflows from sales of oil and gas 818 — 5,101 4,393 158,643 — 168,955
Future production costs 503 — 982 233 73,496 — 75,214
Future development costs 75 — 697 100 5,452 — 6,324
Future income tax expenses — — 1,539 1,120 24,374 — 27,033
Future net cash flows 240 — 1,883 2,940 55,321 — 60,384
Effect of discounting net cash flows at 10% 76 — 672 1,635 20,135 — 22,518
Discounted future net cash flows 164 — 1,211 1,305 35,186 — 37,866
Total consolidated and equity interests in standardized measure of discounted future net cash flows 43,781 35,610 1,890 6,357 52,122 14,506 154,266
(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 312,279 236,954 4,339 15,493 250,850 54,247 874,162
Future production costs 109,915 96,932 1,583 3,167 60,404 12,599 284,600
Future development costs 48,781 37,253 1,921 3,675 17,608 6,083 115,321
Future income tax expenses 21,728 21,738 644 2,801 129,925 9,846 186,682
Future net cash flows 131,855 81,031 191 5,850 42,913 25,719 287,559
Effect of discounting net cash flows at 10% 64,731 34,232 (387) 1,419 23,172 12,898 136,065
Discounted future net cash flows 67,124 46,799 578 4,431 19,741 12,821 151,494
Equity Companies
Future cash inflows from sales of oil and gas 614 — 3,557 5,685 138,978 — 148,834
Future production costs 379 — 766 534 66,969 — 68,648
Future development costs 69 — 709 55 4,243 — 5,076
Future income tax expenses — — 1,106 1,431 19,566 — 22,103
Future net cash flows 166 — 976 3,665 48,200 — 53,007
Effect of discounting net cash flows at 10% 42 — 298 2,099 16,397 — 18,837
Discounted future net cash flows 124 — 677 1,566 31,803 — 34,170
Total consolidated and equity interests in standardized measure of discounted future net cash flows 67,248 46,799 1,255 5,997 51,544 12,821 185,664
As of December 31, 2025
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas 280,283 209,345 3,918 15,372 210,088 54,992 773,998
Future production costs 105,265 94,251 1,458 3,887 51,049 12,502 268,412
Future development costs 57,000 38,312 2,287 4,299 16,712 6,683 125,293
Future income tax expenses 20,341 15,943 345 2,831 106,859 9,376 155,695
Future net cash flows 97,677 60,839 (172) 4,355 35,468 26,431 224,598
Effect of discounting net cash flows at 10% 47,868 22,760 (523) 1,150 19,436 14,066 104,757
Discounted future net cash flows 49,809 38,079 351 3,205 16,032 12,365 119,841
Equity Companies
Future cash inflows from sales of oil and gas 490 — 3,537 3,563 114,161 — 121,751
Future production costs 386 — 736 499 55,221 — 56,842
Future development costs 59 — 623 55 3,285 — 4,022
Future income tax expenses — — 1,031 806 15,740 — 17,577
Future net cash flows 45 — 1,147 2,203 39,915 — 43,310
Effect of discounting net cash flows at 10% 2 — 280 1,220 12,520 — 14,022
Discounted future net cash flows 43 — 867 983 27,395 — 29,288
Total consolidated and equity interests in standardized measure of discounted future net cash flows 49,852 38,079 1,218 4,188 43,427 12,365 149,129
(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) 2023
Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2022 189,609 69,247 258,856
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 5,658 (1,701) 3,957
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (43,836) (10,218) (54,054)
Development costs incurred during the year 15,343 1,502 16,845
Net change in prices, lifting and development costs (120,924) (51,923) (172,847)
Revisions of previous reserves estimates 4,953 5,096 10,049
Accretion of discount 23,006 8,962 31,968
Net change in income taxes 42,591 16,901 59,492
Total change in the standardized measure during the year (73,209) (31,381) (104,590)
Discounted future net cash flows as of December 31, 2023 116,400 37,866 154,266

Consolidated and Equity Interests (millions of dollars) 2024
Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2023 116,400 37,866 154,266
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 42,405 — 42,405
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (51,236) (8,268) (59,504)
Development costs incurred during the year 18,924 1,135 20,059
Net change in prices, lifting and development costs (4,549) (5,811) (10,360)
Revisions of previous reserves estimates 20,779 1,690 22,469
Accretion of discount 15,232 4,853 20,085
Net change in income taxes (6,461) 2,705 (3,756)
Total change in the standardized measure during the year 35,094 (3,696) 31,398
Discounted future net cash flows as of December 31, 2024 151,494 34,170 185,664

Consolidated and Equity Interests (millions of dollars) 2025
Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests
Discounted future net cash flows as of December 31, 2024 151,494 34,170 185,664
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs 12,392 216 12,608
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 (48,105) (7,828) (55,933)
Development costs incurred during the year 18,361 811 19,172
Net change in prices, lifting and development costs (61,606) (5,319) (66,925)
Revisions of previous reserves estimates 14,666 636 15,302
Accretion of discount 18,328 4,207 22,535
Net change in income taxes 14,311 2,395 16,706
Total change in the standardized measure during the year (31,653) (4,882) (36,535)
Discounted future net cash flows as of December 31, 2025 119,841 29,288 149,129

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INDEX TO EXHIBITS
Exhibit Description
3(i) Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015).
3(ii) By-Laws, as amended effective October 25, 2022 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of October 31, 2022).
4(vi) Description of ExxonMobil Capital Stock (incorporated by reference to Exhibit 4(vi) to the Registrant's Annual Report on Form 10-K for 2019).
10(iii)(a.1) 2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2017).*
10(iii)(a.2) Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2016).*
10(iii)(a.3) Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.*
10(iii)(b.1) Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual Report on Form 10-K for 2023).*
10(iii)(b.2) Earnings Bonus Unit instrument (incorporated by reference to Exhibit 10(iii)(b.2) to the Registrant's Annual Report on Form 10-K for 2019).*
10(iii)(b.3) Amendment of 2018 and 2019 Earnings Bonus Unit instruments, effective November 23, 2021 (incorporated by reference to Exhibit 99.1 to the Registrant's Report on Form 8-K of November 30, 2021).*
10(iii)(b.4) Pioneer Natural Resources Company Second Amended and Restated 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10(iii)(b.4) to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2024).*
10(iii)(c.1) ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant's Annual Report on Form 10-K for 2022).*
10(iii)(c.2) ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant's Annual Report on Form 10-K for 2022).*
10(iii)(c.3) ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual Report on Form 10-K for 2023).*
10(iii)(d) ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2016).*
10(iii)(f.1) 2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2018).*
10(iii)(f.2) Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Annual Report on Form 10-K for 2016).*
10(iii)(f.3) Form of restricted stock grant letter for non-employee directors.*
10(iii)(f.4) Standing resolution for non-employee director cash fees dated 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).*
14 Code of Ethics and Business Conduct.
19 Insider Trading Policy (incorporated by reference to Exhibit 19 to the Registrant’s Annual Report on Form 10-K for 2024).
21 Subsidiaries of the registrant.
23 Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31.1 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.
31.2 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Financial Officer.
31.3 Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.
32.1 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.
32.2 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Financial Officer.
32.3 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.
97 Policy Relating to Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97 to the Registrant’s Annual Report on Form 10-K for 2023).
101 Interactive data files (formatted as Inline XBRL).
104 Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101).
* Management contract or compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K.

The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EXXON MOBIL CORPORATION
By: /s/ DARREN W. WOODS
Dated February 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

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