Exxon Mobil
Annual Report 2023

Plain-text annual report

2023 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, 2023 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 (State or other jurisdiction of incorporation or organization) 13-5409005 (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 Common Stock, without par value 0.142% Notes due 2024 0.524% Notes due 2028 0.835% Notes due 2032 1.408% Notes due 2039 Trading Symbol XOM XOM24B XOM28 XOM32 XOM39A Name of Each Exchange on Which Registered New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange 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 Non-accelerated filer ☑ ☐ 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, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $107.25 on the New York Stock Exchange composite tape, was in excess of $429 billion. Class Common stock, without par value Outstanding as of January 31, 2024 3,967,844,307 Documents Incorporated by Reference: Proxy Statement for the 2024 Annual Meeting of Shareholders (Part III) EXXON MOBIL CORPORATION FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2023 TABLE OF CONTENTS PART I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 1C. Cybersecurity Item 2. Item 3. Item 4. Properties Legal Proceedings Mine Safety Disclosures Information about our Executive Officers PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Financial Statements and Supplementary Data Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections PART III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services PART IV Item 15. Exhibit and Financial Statement Schedules Item 16. Form 10-K Summary Financial Section Index to Exhibits Signatures Exhibits 31 and 32 — Certifications 1 2 7 8 9 28 28 29 30 30 30 31 31 31 32 32 32 32 33 33 33 33 33 34 134 135 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 business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses. Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include 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. In October 2023 the Corporation entered into a merger agreement with Pioneer Natural Resources Company (Pioneer), an independent oil and gas exploration and production company, in exchange for ExxonMobil common stock. The transaction is currently expected to close in the second quarter of 2024, subject to regulatory approvals. For additional information, see "Note 21: Mergers and Acquisitions" in the Financial Section of this report. 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 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 18: Disclosures about Segments and Related Information”. 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 2023. For technology licensed to third parties, revenues totaled approximately $155 million in 2023. 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. Over 60 percent of our global employee workforce is from outside the U.S., and over the past decade 39 percent of our global hires for management, professional and technical positions were female and 37 percent of our U.S. hires for management, professional and technical positions were minorities. With over 160 nationalities represented in the company, we encourage and respect diversity of thought, ideas, and perspective from our workforce. We consider and monitor diversity through all stages of employment, including recruitment, training, and development of our employees. We also work closely with the communities where we operate to identify and invest in initiatives that help support local needs, including local talent and skill development. The number of regular employees was 62 thousand, 62 thousand, and 63 thousand at years ended 2023, 2022, and 2021, 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. 1 As discussed in "Item 1A. Risk Factors" 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. Risk Factors” and “Item 2. Properties” in this report. 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 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, 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, especially in the Energy Products, Chemical Products, and Specialty Products segments. Our pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium also depends on the growth and development of markets for those products and services, including implementation of supportive government policies and developments in technology to enable those products and services to be provided on a cost-effective basis at commercial scale. See "Climate Change and the 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 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, periods of civil unrest, government regulation or austerity programs, trade tariffs or broader breakdowns in global trade, security or public health issues and responses, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, 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 and customers to fulfill their commitments to ExxonMobil. Our future business results, including 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; 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 impact our results, include technological improvements in energy efficiency; seasonal weather patterns; increased competitiveness of, or government policy support for, alternative energy sources; changes in technology that alter fuel choices, such as technological advances in energy storage or other critical areas that make wind, solar, hydrogen, nuclear or other alternatives more competitive for power generation; changes in 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 the Energy Transition” below. 2 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 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 costs; 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. 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 trading purposes. Additional information regarding the potential future impact of market factors on our businesses is included or incorporated by reference under "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in this report. Government and Political Factors ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations. Access limitations. A number of countries limit access to their oil and gas resources, including by restricting leasing or permitting activities, or 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 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. Restrictions on doing business. ExxonMobil is subject to laws and sanctions imposed by the United States or by other jurisdictions where we do business that may prohibit ExxonMobil or its affiliates from doing business in certain countries or restrict the kind of business that may be conducted, including acquiring or divesting certain assets. 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 business lack well-developed legal systems, have not yet adopted or may be unable to maintain clear regulatory frameworks, 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, 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. 3 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 of settled law (including changes that result from international treaties and accords) and changes in policy that could adversely affect our results, such as: • • • • • • • • increases in taxes, duties, or government royalty rates (including retroactive claims or punitive taxes on oil, gas and petrochemical operations); price controls; changes in environmental regulations or other laws that increase our cost of operation or compliance or reduce or delay available business opportunities (including changes in laws affecting offshore drilling operations, standards to complete decommissioning, water use, emissions, hydraulic fracturing, or production or use of new or recycled plastics, as well as laws and regulations affecting trading); actions by policy-makers, regulators, or other actors to delay or deny necessary licenses and permits, restrict the availability of oil and gas leases or the transportation or export of our products, 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, the use of alternative fuels or uncompetitive fuel components; adoption of disclosure regulations that could create competitive disadvantages, require us to incur disproportionate costs, or 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, or by requiring 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, renegotiate terms unilaterally, or expropriate assets. 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, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur; by government 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 and has begun to be applied to some of our competitors in the European Union. Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, cybersecurity attacks, the application of national security laws or policies that result in restricting our ability to do business in a particular jurisdiction, and other local 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. Climate Change and the 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, regulatory frameworks to reduce greenhouse gas emissions including emissions from the production and use of oil and gas and their products as well as the use 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 and reflect substantial uncertainties. The company’s objective 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 operations with continued technology development and policy support where ExxonMobil is the operator, carries risks that the transition, including underlying technologies, 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. The success of our strategy for the energy transition 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. 4 Greenhouse gas restrictions. Government actions intended to reduce greenhouse gas emissions include adoption of cap and trade regimes, carbon taxes, 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, 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 and other actors and their agents also increasingly seek to 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 and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering emissions. Technology and lower-emission solutions. Achieving societal ambitions to reduce greenhouse gas emissions and ultimately achieve net zero will require new technologies to reduce the cost and increase the scalability of alternative energy sources, as well as technologies such as carbon capture and storage (CCS). CCS technologies, focused initially on capturing and sequestering CO2 emissions from high-intensity industrial activities, can assist in meeting society’s objective to mitigate atmospheric greenhouse gas levels while also helping ensure the availability of the reliable and affordable energy the world requires. ExxonMobil has established a Low Carbon Solutions (LCS) business unit to advance the development and deployment of these technologies and projects, including CCS, hydrogen, lower-emission fuels, and lithium, breakthrough energy efficiency processes, advanced energy-saving materials, 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 advanced lower-emission energy technologies. Our future results and ability to grow our LCS business, help nations meet their emission-reduction goals, and succeed through the energy transition 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. Policy and market development. The scale of the world’s energy system means that, in addition to developments in technology as discussed above, a successful energy transition will require appropriate support from governments and private participants throughout the global economy. Our ability to develop and deploy CCS and other lower- emission 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 continued development of supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained could adversely impact these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without 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 manage successfully those factors that are, at least in part, within our control, including our capital allocation 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. 5 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 lower-emission 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; model and optimize reservoir performance; 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 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 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. 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, including the acquisition of Pioneer Natural Resources Company. This requires continuous management focus, including technology integration and improvements, cost control, productivity enhancements, harmonizing the 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 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 and policy environment, 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, including successfully applying advances in the ability to process very large amounts of data to our businesses. Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the inherent risks of oil, gas, and petrochemical operations, 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 and avoiding spills or 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. 6 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 covers 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 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 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. 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; 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; 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 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. 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. 7 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 IT, with support from cross-functional teams led by ExxonMobil information technology (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. 8 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 2023 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, 2023 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 (1) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Equity Companies United States Europe Africa Asia Total Equity Company Total Developed Undeveloped Consolidated Subsidiaries (1) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Equity Companies United States Europe Africa Asia Total Equity Company Total Undeveloped Total Proved Reserves 1,208 433 4 204 1,948 35 3,832 7 3 5 329 344 4,176 894 561 — 20 719 26 2,220 — — — 451 451 2,671 6,847 527 — — 13 48 10 598 4 — — 109 113 711 604 — — — 32 2 638 — — — 220 220 858 — 2,307 — — — — 2,307 — — — — — 2,307 — 107 — — — — 107 — — — — — 107 1,569 2,414 — 242 — — — — 242 — — — — — 242 — 112 — — — — 112 — — — — — 112 354 8,138 329 307 220 1,935 3,163 14,092 57 290 780 4,223 5,350 19,442 4,125 191 — — 859 2,695 7,870 — 54 — 7,098 7,152 15,022 3,091 3,037 55 254 2,318 572 9,327 21 51 135 1,142 1,349 10,676 2,186 812 — 20 894 477 4,389 — 9 — 1,854 1,863 6,252 34,464 16,928 (1) Other Americas includes proved developed reserves of 324 million barrels of crude oil and 178 billion cubic feet of natural gas, as well as proved undeveloped reserves of 549 million barrels of crude oil and 179 billion cubic feet of natural gas. 9 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. Risk Factors". 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 well and reservoir information such as flow rates and reservoir pressures. 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 2023 Additions to ExxonMobil’s proved reserves in 2023 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 served 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. 10 2. Proved Undeveloped Reserves At year-end 2023, approximately 6.3 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 37 percent of the 16.9 GOEB reported in proved reserves. This compares to 6.6 GOEB of proved undeveloped reserves reported at the end of 2022. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 0.8 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to development activities in the United States, Guyana, Australia, and the United Arab Emirates. In 2023, extensions and discoveries, primarily in the United States and Guyana, resulted in the addition of approximately 1.1 GOEB of proved undeveloped reserves. Also, the Corporation reclassified approximately 0.6 GOEB of proved undeveloped reserves which no longer met the SEC definition of proved reserves, primarily in the United States. Overall, investments of $14.6 billion were made by the Corporation during 2023 to progress the development of reported proved undeveloped reserves, including $14.3 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. These investments represented 74 percent of the $19.8 billion in total reported Upstream capital and exploration expenditures. 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, Kazakhstan, the United Arab Emirates, and the United States 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 Kazakhstan, the proved undeveloped reserves are related to the remainder of the Tengizchevroil joint venture development that includes a production license in the Tengiz - Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. 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. 11 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) Crude oil and natural gas liquids production Consolidated Subsidiaries (1) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total crude oil and natural gas liquids production Bitumen production Consolidated Subsidiaries Canada/Other Americas Synthetic oil production Consolidated Subsidiaries Canada/Other Americas Total liquids production (millions of cubic feet daily) Natural gas production available for sale Consolidated Subsidiaries (1) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total natural gas production available for sale (thousands of oil-equivalent barrels daily) Oil-equivalent production 2023 2022 2021 Crude Oil NGL Crude Oil NGL Crude Oil NGL 556 240 2 216 417 24 1,455 8 2 1 216 227 1,682 238 2 — 4 28 12 284 1 — — 60 61 345 523 196 2 233 407 27 1,388 41 2 — 216 259 1,647 211 2 — 5 23 16 257 1 — — 59 60 317 482 130 16 241 407 28 1,304 43 3 — 207 253 1,557 195 3 3 7 21 15 244 1 — — 60 61 305 355 327 365 67 2,449 2,292 96 266 35 915 1,298 4,902 19 148 90 2,575 2,832 7,734 3,738 63 2,354 2,531 148 306 64 779 1,440 5,268 20 361 7 2,639 3,027 8,295 3,737 62 2,289 2,724 195 377 43 807 1,280 5,426 22 431 — 2,658 3,111 8,537 3,712 (1) Other Americas includes crude oil production for 2023, 2022, and 2021 of 178 thousand, 120 thousand, and 48 thousand barrels daily, respectively; and natural gas production available for sale for 2023, 2022, and 2021 of 67 million, 45 million, and 36 million cubic feet daily, respectively. 12 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) 2023 Consolidated Subsidiaries Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil Equity Companies Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Average production costs, per oil-equivalent barrel - total Total Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil 2022 Consolidated Subsidiaries Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil Equity Companies Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Average production costs, per oil-equivalent barrel - total Total Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total 71.99 64.10 13.64 — — 36.37 — — 77.82 — 22.22 43.99 74.13 64.10 16.71 — — 39.09 — — 91.32 71.43 21.17 — — 23.77 — — 90.91 — 21.10 26.86 91.15 71.43 21.14 — — 25.43 — — 82.70 44.72 2.04 — — 20.70 — — 71.92 — 5.89 6.74 82.66 44.72 4.81 — — 19.79 — — 103.45 57.83 2.57 — — 21.68 — — 60.00 — 2.72 42.24 103.42 57.83 2.59 — — 21.79 — — 79.50 29.81 2.40 — — 5.26 — — 74.59 45.64 8.54 2.77 77.83 40.59 6.93 — — 3.91 — — 94.94 35.77 2.60 — — 7.31 — — 94.32 59.52 13.08 1.45 94.73 52.85 10.70 — — 4.02 — — 70.26 34.35 9.31 — — 5.55 — — — — — — 70.26 34.35 9.31 — — 5.55 — — 94.43 46.91 11.47 — — 4.97 — — — — — — 94.43 46.91 11.47 — — 4.97 — — 78.43 25.12 4.26 49.64 77.56 12.05 23.80 45.91 74.63 45.19 9.15 5.09 77.92 28.66 6.05 49.64 77.56 10.63 23.80 45.91 96.16 39.37 7.48 64.12 96.08 13.09 29.90 51.52 94.32 59.05 13.97 5.57 95.88 43.09 9.85 64.12 96.08 11.43 29.90 51.52 75.45 23.88 1.16 — — 9.70 — — 75.48 19.13 5.25 53.49 75.45 23.86 1.19 — — 10.15 — — 93.60 38.54 5.37 — — 9.40 — — 94.58 39.53 5.49 40.42 93.67 38.55 5.37 — — 10.57 — — 80.51 24.44 2.57 49.64 77.56 19.94 23.80 45.91 — — — — 80.51 24.44 2.57 49.64 77.56 19.94 23.80 45.91 97.05 45.22 4.40 64.12 96.08 24.63 29.90 51.52 — — — — 97.05 45.22 4.40 64.12 96.08 24.63 29.90 51.52 13 (dollars per unit) 2021 Consolidated Subsidiaries Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil Equity Companies Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Average production costs, per oil-equivalent barrel - total Total Average production prices Crude oil, per barrel NGL, per barrel Natural gas, per thousand cubic feet Bitumen, per barrel Synthetic oil, per barrel Average production costs, per oil-equivalent barrel - total Average production costs, per barrel - bitumen Average production costs, per barrel - synthetic oil United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total 65.03 32.24 3.02 — — 8.33 — — 67.06 29.94 3.11 30.51 65.20 32.23 3.02 — — 9.24 — — 68.56 30.51 2.92 44.26 64.73 22.47 22.69 48.87 — — — — 68.56 30.51 2.92 44.26 64.73 22.47 22.69 48.87 66.20 42.31 11.83 — — 25.31 — — 62.60 — 8.19 38.82 65.54 42.31 9.89 — — 31.79 — — 70.21 54.57 1.67 — — 18.92 — — — — — — 70.21 54.57 1.67 — — 19.04 — — 67.28 32.62 2.11 — — 7.16 — — 65.85 52.14 6.54 1.59 66.80 47.10 5.50 — — 4.06 — — 69.00 43.07 6.64 — — 5.14 — — — — — — 69.00 43.07 6.64 — — 5.14 — — 67.14 33.65 4.33 44.26 64.73 12.15 22.69 48.87 66.01 51.64 6.74 6.67 66.96 37.27 5.21 44.26 64.73 10.92 22.69 48.87 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. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. 14 4. Drilling and Other Exploratory and Development Activities A. Number of Net Productive and Dry Wells Drilled 2023 2022 2021 Net Productive Exploratory Wells Drilled Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total productive exploratory wells drilled Net Dry Exploratory Wells Drilled Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total dry exploratory wells drilled 15 — 1 1 — — — 2 — — — — — 2 1 3 — — — — 4 — — — — — 4 1 3 — — — — 4 — — — — — 4 — 4 — — — — 4 — — — — — 4 1 5 — — — — 6 — — — — — 6 1 3 — — — — 4 — — — — — 4 Net Productive Development Wells Drilled Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total productive development wells drilled Net Dry Development Wells Drilled Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total dry development wells drilled 2023 2022 2021 446 47 1 4 5 — 503 2 — — 6 8 511 — — — — — — — — — — — — — 473 33 — 3 5 — 514 49 — — 10 59 573 — — — — — — — — — — — — — 433 28 1 1 4 — 467 13 1 1 5 20 487 4 — — — — — 4 — — — — — 4 Total number of net wells drilled 517 581 501 16 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 2023, the company’s share of net production of synthetic crude oil was about 67 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 by pipeline and rail. During 2023, average net production at Kearl was about 249 thousand barrels per day. 5. Present Activities A. Wells Drilling Wells Drilling Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total gross and net wells drilling Year-End 2023 Year-End 2022 Gross Net Gross Net 582 42 3 4 25 3 659 9 — — 61 70 409 29 1 1 5 1 446 — — — 4 4 804 54 2 10 18 1 889 13 — — 8 21 472 40 1 2 5 — 520 2 — — 3 5 729 450 910 525 17 B. Review of Principal Ongoing Activities United States Net acreage totaled 9.3 million acres at year-end 2023, of which 0.2 million acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. Development activities continued on the Golden Pass LNG export project. During the year, a total of 446.9 net exploratory and development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico. In addition, ExxonMobil closed on the sale of its interest in the Aera Energy joint venture and acquired Denbury Inc. (Denbury), which includes Gulf Coast and Rocky Mountain oil and natural gas operations. Net acreage in the Gulf of Mexico totaled 0.1 million acres at year-end 2023. Participation in Alaska production and development continued with a total of 2.3 net development wells completed. Canada / Other Americas Canada Oil and Gas Operations: Net acreage totaled 3.9 million acres at year-end 2023, of which 2.1 million acres were offshore. A total of 0.9 net exploratory and development wells were completed during the year. In Situ Bitumen Operations: Net acreage totaled 0.5 million onshore acres at year-end 2023. During the year, a total of 32 net development wells at Cold Lake were completed. Argentina Net acreage totaled 2.9 million acres at year-end 2023, of which 2.6 million acres were offshore. During the year, a total of 4.4 net development wells were completed. Brazil Net acreage totaled 2.6 million offshore acres at year-end 2023. During the year, a total of 0.4 net development well was completed. Development activities continued on the Bacalhau Phase 1 project. Guyana Net acreage totaled 4.6 million offshore acres at year-end 2023. During the year, a total of 12.6 net exploratory and development wells were completed. The Payara development commenced operations with the Prosperity floating production, storage and offloading vessel, and development activities continued on the Yellowtail project. The Uaru project was funded in 2023. Europe Germany Net acreage totaled 1.4 million onshore acres at year-end 2023. During the year, a total of 1.4 net exploratory and development wells were completed. Netherlands Net interest in licenses totaled 1.3 million acres at year-end 2023, of which 0.3 million acres were offshore. Groningen gas production ceased on October 1, 2023, at the Dutch government’s instruction. In case of severe cold weather conditions, the Dutch government could mandate the re-start of gas production. United Kingdom Net interest in licenses totaled 0.1 million offshore acres at year-end 2023. 18 Africa Angola Net acreage totaled 3 million acres at year-end 2023, of which 2.9 million acres were offshore. During the year, a total of 3.7 net development wells were completed. Equatorial Guinea Net acreage totaled 0.1 million offshore acres at year-end 2023. ExxonMobil is actively taking steps to exit its operations in the country. Mozambique Net acreage totaled 0.1 million offshore acres at year-end 2023. In 2023, 0.6 million net offshore acres were relinquished outside of the core Area 4 development. Within Area 4, ExxonMobil participated in the co-venturer-operated Coral South Floating LNG, a gross 3.4 million metric tons per year LNG facility. Nigeria Net acreage totaled 0.9 million offshore acres at year-end 2023. During the year, a total of 0.2 net development well was completed. Asia Azerbaijan Net acreage totaled 7 thousand offshore acres at year-end 2023. During the year, a total of 0.5 net development wells were completed. Indonesia Net acreage totaled 0.1 million onshore acres at year-end 2023. Iraq Net acreage totaled 25 thousand onshore acres at year-end 2023. During the year, a total of 1.1 net development wells were completed. In 2023, ExxonMobil completed a partial sale of 10 percent participating interest and in early 2024 closed on the sale of its remaining interest resulting in a full exit from the country. Kazakhstan Net acreage totaled 0.3 million acres at year-end 2023, of which 0.2 million acres were offshore. During the year, a total of 1 net development wells were completed. Development activities continued on the Tengiz Expansion project. Malaysia Net interests in production sharing contracts covered 0.2 million offshore acres at year-end 2023. During the year, a total of 0.5 net development well was completed. Qatar Through joint ventures with QatarEnergy, net acreage totaled 80 thousand offshore acres at year-end 2023. During the year, a total of 4.7 net development wells were completed. ExxonMobil participated in 52.3 million metric tons per year gross liquefied natural gas capacity and 3.4 billion cubic feet per day of flowing gas capacity at year-end. Development activities continued on the North Field East project and North Field Production Sustainment projects. Thailand Net acreage in concessions totaled 16 thousand onshore acres at year-end 2023. During the year, a total of 0.2 net development wells were completed. United Arab Emirates Net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2023. During the year, a total of 3.1 net development wells were completed. Development activities continued on the Upper Zakum 1 MBD Sustainment project. 19 Australia / Oceania Australia Net acreage totaled 1.2 million offshore acres and nine thousand onshore acres at year-end 2023. The co-venturer-operated Gorgon Jansz liquefied natural gas (LNG) development consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million metric tons per year LNG facility, and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia. During the year, development activities continued on the Gorgon Stage 2 project and Jansz Io Compression project. Papua New Guinea Net acreage totaled 2.1 million onshore acres at year-end 2023. During the year, a total of 0.4 net development wells were completed. The Papua New Guinea (PNG) liquefied natural gas (LNG) integrated development includes gas production and processing facilities in the PNG Highlands, onshore and offshore pipelines, and a 6.9 million metric tons per year LNG facility near Port Moresby. 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 18.5 million acres at year-end 2023. During the year, a total of 0.6 net exploratory well was completed. 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 78 million barrels of oil and 2.5 trillion cubic feet of natural gas for the period from 2024 through 2026. 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. 20 7. Oil and Gas Properties, Wells, Operations and Acreage A. Gross and Net Productive Wells Gross and Net Productive Wells Year-End 2023 Year-End 2022 Oil Gas Oil Gas Gross Net Gross Net Gross Net Gross Net Consolidated Subsidiaries United States Canada/Other Americas Europe Africa Asia Australia/Oceania 21,193 4,193 9,503 4,131 8,210 2,901 476 605 995 449 125 204 293 84 396 21 148 98 4,801 1,034 198 8 85 40 19,006 4,394 7,576 11,495 4,310 2,903 536 590 999 473 127 191 318 89 433 24 147 92 7,516 1,033 205 10 86 38 Total Consolidated Subsidiaries 27,911 14,340 11,774 6,166 25,998 12,611 15,094 8,888 Equity Companies United States Europe Africa Asia Total Equity Companies 2,634 340 3,322 57 — 234 2,925 20 — 58 454 6 145 418 3,927 Total gross and net productive wells 30,836 14,758 15,701 329 139 2 33 12,068 4,777 3,341 57 — 233 20 — 58 482 6 145 503 6,669 12,358 38,356 4,855 3,974 17,466 19,068 331 150 2 33 516 9,404 There were 18,518 gross and 16,171 net operated wells at year-end 2023 and 19,571 gross and 17,165 net operated wells at year-end 2022. The number of wells with multiple completions was 467 gross in 2023 and 1,010 gross in 2022. 21 B. Gross and Net Developed Acreage Gross and Net Developed Acreage (thousands of acres) Year-End 2023 Year-End 2022 Gross Net Gross Net Consolidated Subsidiaries United States (1) Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total gross and net developed acreage 10,354 2,145 983 2,109 1,582 3,174 20,347 583 3,590 178 665 5,016 25,363 6,566 1,526 560 704 451 1,033 10,840 113 1,109 44 157 1,423 12,263 11,022 2,113 1,238 2,186 1,582 3,242 21,383 702 3,646 178 665 5,191 26,574 6,681 1,509 580 736 462 1,067 11,035 166 1,117 44 157 1,484 12,519 (1) Includes developed acreage in Other Americas of 559 gross and 342 net thousands of acres for 2023 and 490 gross and 311 net thousands of acres for 2022. Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage. C. Gross and Net Undeveloped Acreage Gross and Net Undeveloped Acreage (thousands of acres) Year-End 2023 Year-End 2022 Gross Net Gross Net Consolidated Subsidiaries (1) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Total Consolidated Subsidiaries Equity Companies United States Europe Africa Asia Total Equity Companies Total gross and net undeveloped acreage 6,738 30,773 12,489 18,309 766 4,811 73,886 — 381 418 298 1,097 74,983 2,602 15,012 8,173 12,696 227 2,309 41,019 — 110 104 19 233 41,252 6,455 32,441 12,592 20,620 766 4,811 77,685 150 482 418 296 1,346 79,031 2,587 15,838 8,231 13,113 227 2,309 42,305 61 131 104 19 315 42,620 (1) Includes undeveloped acreage in Other Americas of 24,221 gross and 11,548 net thousands of acres for 2023 and 25,096 gross and 11,977 net thousands of acres for 2022. 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. 22 D. Summary of Acreage Terms United States 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 regarding private property, a “fee interest” is acquired where the underlying mineral interests are owned outright. Canada / Other Americas Canada Exploration licenses or leases in onshore areas are acquired for varying periods of time with renewals or extensions possible. These licenses or leases entitle the holder to continue existing licenses or leases upon completing specified work. In general, these license and lease agreements are held as long as there is proven production capability on the licenses and leases. Offshore exploration licenses are generally held by work commitments of various amounts and rentals. 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. Argentina The Federal Hydrocarbon Law was amended in 2014. Pursuant to the amended law, the production term for an onshore unconventional concession is 35 years and 25 years for a conventional concession, with unlimited 10-year extensions possible once a field has been developed. In 2019, the government granted three offshore exploration licenses, with terms of eight years, divided into two exploration periods of four years, with an optional extension of five years for each license. Brazil The exploration and production of oil and gas are governed by concession contracts and production sharing contracts (PSCs). Concession contracts provide for an exploration period of up to eight years and a production period of 27 years. PSCs provide for an exploration period of up to seven years and a production period of up to 28 years. Guyana 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. Europe Germany Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions up to three years each. Extensions are subject to specific minimum work commitments. Production licenses were historically granted for 20 to 25 years with multiple possible extensions subject to production on the license. Netherlands Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the license and are based on the Mining Law. Production rights granted prior to January 1, 2003, remain subject to their existing terms and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years. 23 United Kingdom Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case- by-case basis until they become producing areas; or licenses terminate in all other areas. The majority of traditional licenses currently issued have an initial exploration term of four years with a second term extension of four years, and a final production term of 18 years, with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term. Africa Angola Exploration and production activities are governed by either production sharing agreements or other contracts with initial exploration terms ranging from three to four years with options to extend from one to five years. The production periods range from 20 to 30 years, and the agreements generally provide for negotiated extensions. Equatorial Guinea Exploration, development and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines and Hydrocarbons. The production period for crude oil is 30 years. ExxonMobil is actively taking steps to exit its operations in the country. Mozambique Exploration and production activities are generally governed by concession contracts with the Government of the Republic of Mozambique, represented by the Ministry of Mineral Resources and Energy. An interest in Area 4 offshore Mozambique was acquired in 2017. Terms for Area 4 are governed by the Exploration and Production Concession Contract (EPCC) for Area 4 Offshore of the Rovuma Block. The EPCC expires 30 years after an approved plan of development becomes effective for a given discovery area. In 2018, an interest was acquired in Area 5 offshore blocks A5-B, Z5-C, and Z5-D. Blocks Z5-C and Z5-D were relinquished in 2022. In 2023, the initial exploration phase expired on block A5-B, resulting in a relinquishment of the remaining Area 5 acreage. Nigeria Exploration and production activities in the deepwater offshore areas are governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Company Limited (NNPCL). NNPCL typically holds the underlying license or lease. The terms of the PSCs are generally 30 years (comprised of a 10- year exploration period and a 20-year production period). Exploration and production activities in the shallow-water offshore areas are governed by Oil Mining Leases granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) and have been renewed in 2011 for a further period of 20 years. Operations under these pre-1969 Oil Mining Leases are conducted under a joint venture agreement with NNPCL rather than a PSC. Commercial terms applicable to the existing joint venture oil production are defined by the Petroleum Profits Tax Act. The 2021 Petroleum Industry Act will govern any further renewals to the term of the PSCs, licenses, or leases. Asia Azerbaijan The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field was established for an initial period of 30 years starting from the PSA execution date in 1994. The PSA was amended in September 2017 to extend the term by 25 years to 2049. Indonesia Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract (PSC). The current PSCs have an exploration period of six years, which can be extended once for a period of four years with a total contract period of 30 years including an exploitation period. PSC terms can be extended for a maximum of 20 years for each extension with the approval of the government. 24 Iraq Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with Basra Oil Company of the Iraqi Ministry of Oil for the rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for a period of five to 15 years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels. In early 2024, ExxonMobil closed on the sale of its remaining interest resulting in a full exit from the country. Kazakhstan Onshore exploration and production activities are governed by the production license, exploration license, and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993. Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is 20 years from the date of declaration of commerciality with the possibility of two 10-year extensions. Malaysia Production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The PSCs have production terms of 25 years. Extensions are generally subject to the national oil company’s prior written approval. Qatar The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects. The initial terms for these rights generally extend for 25 years. Extensions and terms are subject to State of Qatar approval. Thailand The Petroleum Act of 1971 allows production under ExxonMobil’s concessions for 30 years with a 10-year extension at terms generally prevalent at the time. United Arab Emirates An interest in the development and production activities of the offshore Upper Zakum field was acquired in 2006. In 2017, the governing agreements were extended to 2051. Australia / Oceania Australia Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application but are likely to become commercially viable within 15 years. These are granted for periods of five years, and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter indefinitely, i.e., for the life of the field. Effective from July 1998, new production licenses are granted indefinitely. In each case, a production license may be terminated if no production operations have been carried on for five years. Papua New Guinea Exploration and production activities are governed by the Oil and Gas Act. Petroleum prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum development licenses are granted for an initial 25-year period. An extension for further consecutive period(s) of up to 20 years may be granted at the Minister’s discretion. Petroleum retention licenses may be granted for gas resources that are not commercially viable at the time of application but may become commercially viable within the maximum possible retention time of 15 years. Petroleum retention licenses are granted for an initial five-year period, and may only be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. 25 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 2023 (1) United States Joliet Illinois Baton Rouge Louisiana Texas Texas Texas Texas Alberta Ontario Ontario Belgium Belgium France France Germany Netherlands United Kingdom United Kingdom China Singapore Saudi Arabia Saudi Arabia Baytown Beaumont Corpus Christi Mont Belvieu Total United States Canada Strathcona Nanticoke Sarnia Total Canada Europe Antwerp Meerhout Fos-sur-Mer Gravenchon Karlsruhe (4) Rotterdam Fawley Fife Total Europe Asia Pacific Fujian Singapore Total Asia Pacific Middle East Al Jubail Yanbu Total Middle East Total Worldwide ExxonMobil Interest % ExxonMobil’s Share of Refining Capacity (2) (thousands of barrels daily) Ethylene Polyethylene Polypropylene (millions of metric tons per year) ■ ■ ▲ ● ■ ▲ ● ■ ▲ ● ● ● ■ ■ ■ ■ ● ● ● 100 100 100 100 50 100 69.6 69.6 69.6 100 100 (3) 82.9 ■ ■ ▲ ● 82.9 / 100 ■ ■ ▲ ● ■ ▲ ● ● 100 100 50 25 ● ■ ■ ▲ ● ▲ ● ● ■ 25 100 50 50 258 523 565 609 — — 1,955 197 113 123 433 307 — 133 244 78 192 262 — 1,216 67 592 659 — 200 200 — 1.1 4.0 0.9 0.9 — 6.9 — — 0.3 0.3 — — — 0.4 — — — 0.4 0.8 0.3 1.9 2.2 0.7 1.0 1.7 — 1.3 — 1.7 0.7 2.3 6.0 — — 0.5 0.5 0.4 0.5 — 0.4 — — — — 1.3 0.2 1.9 2.1 0.7 0.7 1.4 4,463 11.9 11.2 — 0.9 0.8 — — — 1.7 — — — — — — — 0.3 — — — — 0.3 0.2 0.9 1.1 — 0.2 0.2 3.3 ■ 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) ExxonMobil ownership in Gravenchon is split 82.9 percent and 100 percent between the refining and chemical operations, respectively. (4) The Corporation announced a sales agreement relating to ExxonMobil's ownership interest in this asset and expects the transaction to close in 2024. Due to rounding, numbers presented above may not add up precisely to the totals indicated. 26 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 2023 Owned/leased Distributors/resellers United States Canada Europe Asia Pacific Latin America Middle East/Africa Worldwide 10,722 2,477 3,573 931 523 255 18,481 — — 169 284 — 169 622 27 Total 10,722 2,477 3,742 1,215 523 424 19,103 ITEM 3. LEGAL PROCEEDINGS ExxonMobil has elected to use a $1 million threshold for disclosing environmental proceedings. As reported in the Corporation’s Form 10-Q for the third quarter of 2023, the State of Texas filed suit against ExxonMobil Oil Corporation (EMOC) on August 19, 2020, seeking penalties and injunctive relief in connection with alleged unauthorized emissions events at EMOC’s Beaumont Refinery in Texas from 2017 to 2020. The suit, captioned State of Texas v. ExxonMobil Oil Corporation, was filed in the 98th Judicial District Court of Travis County, Texas (the “98th Judicial District Court”). In September 2023, the State of Texas and EMOC agreed to settle the alleged violations upon payment of $1.6 million to the State of Texas (the “Settlement”) pending approval by the 98th Judicial District Court. In November 2023, the 98th Judicial District Court approved the Settlement, and EMOC paid the amounts required under the Settlement in December 2023. Refer to the relevant portions of “Note 16: Litigation and Other Contingencies” of the Financial Section of this report for additional information on legal proceedings. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. 28 Information about our Executive Officers (positions and ages as of February 28, 2024) Name Age Current and Prior Positions (up to five years) Darren W. Woods 59 Chairman of the Board and Chief Executive Officer (since January 1, 2017) Director and President (since January 1, 2016) Neil A. Chapman 61 Senior Vice President (since January 1, 2018) Kathryn A. Mikells 58 Senior Vice President and Chief Financial Officer (since August 9, 2021) Chief Financial Officer and a member of the board of directors for Diageo plc (November 2015 - June 2021) Jack P. Williams, Jr. 60 Senior Vice President (since June 1, 2014) James R. Chapman 54 Vice President, Tax and Treasurer (since November 28, 2022) Dominion Energy, Inc. (prior to November 28, 2022): Executive Vice President, Chief Financial Officer and Treasurer (January 2019 - November 2022) Len M. Fox 60 Vice President and Controller (since March 1, 2021, following a special assignment) Assistant Treasurer, Exxon Mobil Corporation (February 1, 2020 - December 31, 2020) Vice President, Chemical Business Services and Treasurer (June 1, 2015 - January 31, 2020) Jon M. Gibbs 52 President of ExxonMobil Global Projects Company (since April 1, 2021) Senior Vice President, Global Project Delivery, ExxonMobil Global Projects Company (July 1, 2020 - March 31, 2021) President, ExxonMobil Global Services Company (April 1, 2019 - June 30, 2020) Upstream Organization Design Team Lead, ExxonMobil Development Company (January 15, 2019 - March 31, 2019) Vice President, Asia Pacific and Middle East, ExxonMobil Development Company (January 1, 2016 - January 14, 2019) Liam M. Mallon 61 Vice President (since April 1, 2019) Karen T. McKee President, ExxonMobil Upstream Company (since April 1, 2022) President, ExxonMobil Upstream Oil & Gas Company (April 1, 2019 - March 31, 2022) President, ExxonMobil Development Company (January 1, 2017 - March 31, 2019) 57 Vice President (since April 1, 2019) President, ExxonMobil Product Solutions Company (since April 1, 2022) President, ExxonMobil Chemical Company (April 1, 2019 - March 31, 2022) Senior Vice President, Basic Chemicals, Integration & Growth, ExxonMobil Chemical Company (August 1, 2017 - March 31, 2019) Craig S. Morford 65 Vice President and General Counsel (since November 1, 2020) Secretary (since March 1, 2022) Deputy General Counsel (May 1, 2019 - October 31, 2020) Chief Legal and Compliance Officer of Cardinal Health, Inc. (until March 2019) Darrin L. Talley 59 Vice President, Corporate Strategic Planning (since April 1, 2022) President, ExxonMobil Research and Engineering Company (April 1, 2020 - March 31, 2022) Manager, Corporate Strategy, Corporate Strategic Planning (March 15, 2017 - March 31, 2020) 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. 29 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The principal market 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 297,994 registered shareholders of ExxonMobil common stock at December 31, 2023. At January 31, 2024, the registered shareholders of ExxonMobil common stock numbered 296,268. On February 1, 2024, the Corporation declared a $0.95 dividend per common share, payable March 11, 2024. Reference is made to Item 12 in Part III of this report. Issuer Purchases of Equity Securities for Quarter Ended December 31, 2023 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 2023 November 2023 December 2023 Total — 23,692,642 22,318,029 46,010,671 — $104.55 $101.06 $102.86 — 21,626,648 21,319,070 42,945,718 (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. $21.9 $19.7 $17.5 (3) Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1. As required by securities law restrictions, no repurchases will take place during proxy solicitation and voting periods for transactions involving the issuance of ExxonMobil shares. For the Denbury transaction, this period took place during October 2023. For the Pioneer transaction, this period occurred during the first quarter of 2024. (4) In its 2022 Corporate Plan Update released December 8, 2022, the Corporation stated that the company expanded its share repurchase program to up to $50 billion through 2024. This includes $15 billion of repurchases in 2022 and $17.5 billion in 2023. In its 2023 Corporate Plan Update released December 6, 2023, the Corporation stated that after the Pioneer transaction closes, the go-forward share repurchase program pace is expected to increase to $20 billion annually through 2025, 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. 30 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 28, 2024, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 21: Mergers and Acquisitions”; “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, 2023. 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, 2023. The Corporation excluded Denbury Inc. from our assessment of internal control over financial reporting as of December 31, 2023, because it was acquired by the Corporation in a business combination during 2023. Total assets and total revenues of Denbury Inc., a wholly owned subsidiary, represent two percent and less than one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2023, 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. 31 ITEM 9B. OTHER INFORMATION During the three months ended December 31, 2023, 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 2024 annual meeting of shareholders (the “2024 Proxy Statement”): • • • The section entitled “Election of Directors”; 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”. 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 2024 Proxy Statement. 32 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 “Certain Beneficial Owners” and “Director and Executive Officer Stock Ownership” of the registrant’s 2024 Proxy Statement. Plan Category Equity Compensation Plan Information (a) (b) (c) 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 43,076,160 (1) Equity compensation plans not approved by security holders Total (1) The number of restricted stock units to be settled in shares. — 43,076,160 — — — 54,253,587 (2)(3) — 54,253,587 (2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 53,971,387 shares available for award under the 2003 Incentive Program and 282,200 shares available for award under the 2004 Non-Employee Director Restricted Stock 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 “Related Person Transactions and Procedures” of the section entitled “Director and Executive Officer Stock Ownership”; and the portion entitled “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 2024 Proxy Statement. ITEM 14. PRINCIPAL ACCOUNTING 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 2024 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. 33 FINANCIAL SECTION TABLE OF CONTENTS Business Profile Financial Information Frequently Used Terms Management’s Discussion and Analysis of Financial Condition and Results of Operations Forward-Looking Statements Overview Business Environment Business Results Liquidity and Capital Resources Capital and Exploration Expenditures Taxes Environmental Matters Market Risks Critical Accounting Estimates Management’s Report on Internal Control Over Financial Reporting Report of Independent Registered Public Accounting Firm Consolidated Financial Statements Statement of Income Statement of Comprehensive Income Balance Sheet Statement of Cash Flows Statement of Changes in Equity Notes to Consolidated Financial Statements 1. Summary of Accounting Policies 2. Russia 3. Miscellaneous Financial Information 4. Other Comprehensive Income Information 5. Cash Flow Information 6. Additional Working Capital Information 7. Equity Company Information 8. Investments, Advances and Long-Term Receivables 9. Property, Plant and Equipment and Asset Retirement Obligations 10. Accounting for Suspended Exploratory Well Costs 11. Leases 12. Earnings Per Share 13. Financial Instruments and Derivatives 14. Long-Term Debt 15. Incentive Program 16. Litigation and Other Contingencies 17. Pension and Other Postretirement Benefits 18. Disclosures about Segments and Related Information 19. Income and Other Taxes 20. Divestment Activities 21. Mergers and Acquisitions Supplemental Information on Oil and Gas Exploration and Production Activities 34 35 36 37 42 43 44 50 64 68 68 69 69 71 75 76 78 79 80 81 82 83 87 88 89 90 90 91 93 93 95 97 99 100 101 103 104 105 111 114 118 119 120 BUSINESS PROFILE Financial Upstream United States Non-U.S. Total Energy Products United States Non-U.S. Total Chemical Products United States Non-U.S. Total Specialty Products United States Non-U.S. Total Corporate and Financing Corporate total Earnings (Loss) After Income Taxes Average Capital Employed (Non-GAAP) Return on Average Capital Employed (Non-GAAP) Capital and Exploration Expenditures 2023 2022 2023 2022 2023 2022 2023 2022 (millions of dollars) (millions of dollars) (percent) (millions of dollars) 4,202 17,106 21,308 6,123 6,019 12,142 1,626 11 1,637 1,536 1,178 2,714 (1,791) 36,010 11,728 24,751 36,479 8,340 6,626 14,966 2,328 1,215 3,543 1,190 1,225 2,415 (1,663) 55,740 51,957 91,358 143,315 52,555 93,250 145,805 12,540 20,010 32,550 14,702 13,859 28,561 2,148 6,366 8,514 11,787 18,855 30,642 14,694 12,513 27,207 2,072 6,207 8,279 30,500 243,440 16,471 228,404 8.1 18.7 14.9 48.8 30.1 37.3 11.1 0.1 5.7 71.5 18.5 31.9 — 15.0 22.3 26.5 25.0 70.8 35.1 48.8 15.8 9.7 13.0 57.4 19.7 29.2 — 24.9 8,813 10,948 19,761 6,968 10,034 17,002 1,195 1,580 2,775 751 1,962 2,713 63 391 454 1,351 1,059 2,410 1,123 1,842 2,965 46 222 268 622 26,325 59 22,704 See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed. Due to rounding, numbers presented may not add up precisely to the totals indicated. 2023 2022 2023 2022 Operating Net liquids production (thousands of barrels daily) United States Non-U.S. Total Natural gas production available for sale (millions of cubic feet daily) United States Non-U.S. Total 803 1,646 2,449 2,311 5,423 7,734 776 1,578 2,354 2,551 5,744 8,295 Refinery throughput (thousands of barrels daily) United States Non-U.S. Total Energy Products sales (thousands of barrels daily) (2) United States Non-U.S. Total Oil-equivalent production (thousands of oil-equivalent barrels daily) (1) 3,738 3,737 Chemical Products sales (thousands of metric tons) (2) United States Non-U.S. Total Specialty Products sales (thousands of metric tons) (2) United States Non-U.S. Total (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 35 1,848 2,220 4,068 2,633 2,828 5,461 1,702 2,328 4,030 2,426 2,921 5,347 6,779 12,603 19,382 7,270 11,897 19,167 1,962 5,635 7,597 2,049 5,762 7,810 FINANCIAL INFORMATION (millions of dollars, except where stated otherwise) Sales and other operating revenue Net income (loss) attributable to ExxonMobil Earnings (loss) per common share (dollars) Earnings (loss) per common share – assuming dilution (dollars) Earnings (loss) to average ExxonMobil share of equity (percent) Working capital Ratio of current assets to current liabilities (times) Additions to property, plant and equipment Property, plant and equipment, less allowances Total assets Exploration expenses, including dry holes Research and development costs Long-term debt Total debt Debt to capital (percent) Net debt to capital (percent) (1) 2023 2022 2021 334,697 36,010 398,675 55,740 276,692 23,040 8.89 8.89 18.0 13.26 13.26 30.7 31,293 1.48 28,586 1.41 5.39 5.39 14.1 2,511 1.04 29,038 214,940 376,317 18,338 204,692 369,067 12,541 216,552 338,923 751 879 37,483 41,573 16.4 4.5 1,025 824 40,559 41,193 16.9 5.4 1,054 843 43,428 47,704 21.4 18.9 ExxonMobil share of equity at year-end ExxonMobil share of equity per common share (dollars) Weighted average number of common shares outstanding (millions) 204,802 51.57 4,052 195,049 47.78 4,205 168,577 39.77 4,275 Number of regular employees at year-end (thousands) (2) 61.5 62.3 63.0 (1) (2) Debt net of cash. 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. 36 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 calculation. 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 associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash both from operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions. Cash Flow From Operations and Asset Sales (millions of dollars) Net cash provided by operating activities Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments Cash flow from operations and asset sales (Non-GAAP) 2023 2022 2021 55,369 76,797 48,129 4,078 59,447 5,247 82,044 3,176 51,305 Capital Employed (Non-GAAP) Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed. Capital Employed (millions of dollars) Business uses: asset and liability perspective Total assets Less liabilities and noncontrolling interests share of assets and liabilities Total current liabilities excluding notes and loans payable Total long-term liabilities excluding long-term debt Noncontrolling interests share of assets and liabilities Add ExxonMobil share of debt-financed equity company net assets Total capital employed (Non-GAAP) Total corporate sources: debt and equity perspective Notes and loans payable Long-term debt ExxonMobil share of equity Less noncontrolling interests share of total debt Add ExxonMobil share of equity company debt Total capital employed (Non-GAAP) 37 2023 2022 2021 376,317 369,067 338,923 (61,226) (60,980) (8,878) 3,481 (68,411) (56,990) (9,205) 3,705 (52,367) (63,169) (8,746) 4,001 248,714 238,166 218,642 4,090 37,483 204,802 (1,142) 3,481 634 40,559 195,049 (1,781) 3,705 4,276 43,428 168,577 (1,640) 4,001 248,714 238,166 218,642 FREQUENTLY USED TERMS Return on Average Capital Employed (Non-GAAP) Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in our capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions. Return on Average Capital Employed (millions of dollars) Net income (loss) attributable to ExxonMobil Financing costs (after-tax) Gross third-party debt ExxonMobil share of equity companies All other financing costs – net Total financing costs Earnings (loss) excluding financing costs (Non-GAAP) 2023 2022 2021 36,010 55,740 23,040 (1,175) (307) 931 (551) 36,561 (1,213) (198) 276 (1,135) 56,875 (1,196) (170) 11 (1,355) 24,395 Average capital employed (Non-GAAP) 243,440 228,404 222,890 Return on average capital employed – corporate total (Non-GAAP) 15.0% 24.9% 10.9% 38 FREQUENTLY USED TERMS Structural Cost Savings Structural cost savings describe decreases in cash opex excluding energy and production taxes as a result of operational efficiencies, workforce reductions, and other cost saving measures that are expected to be sustainable compared to 2019 levels. Relative to 2019, estimated cumulative structural cost savings totaled $9.7 billion. The total change between periods in expenses below will reflect both structural cost savings and other changes in spend, including market factors, such as inflation and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations. Estimates of cumulative annual structural savings may be revised depending on whether cost reductions realized in prior periods are determined to be sustainable compared to 2019 levels. Structural cost savings are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to understand the Corporation’s efforts to optimize spending through disciplined expense management. Calculation of Structural Cost Savings (billions of dollars) Components of Operating Costs From ExxonMobil’s Consolidated Statement of Income (U.S. GAAP) Production and manufacturing expenses Selling, general and administrative expenses Depreciation and depletion (includes impairments) Exploration expenses, including dry holes Non-service pension and postretirement benefit expense Subtotal ExxonMobil's share of equity company expenses (Non-GAAP) Total Adjusted Operating Costs (Non-GAAP) Total Adjusted Operating Costs (Non-GAAP) Less: Depreciation and depletion (includes impairments) Non-service pension and postretirement benefit expense Other adjustments (includes equity company depreciation and depletion) Total Cash Operating Expenses (Cash Opex) (Non-GAAP) Energy and production taxes (Non-GAAP) 2019 36.8 11.4 19.0 1.3 1.2 69.7 9.1 78.8 78.8 19.0 1.2 3.6 55.0 11.0 2023 36.9 9.9 20.6 0.8 0.7 68.9 10.5 79.4 79.4 20.6 0.7 3.7 54.4 14.9 Total Cash Operating Expenses (Cash Opex) excluding Energy and Production Taxes (Non-GAAP) 44.0 +3.6 +1.6 -9.7 39.5 Market Activity / Other Structural Savings 39 FREQUENTLY USED TERMS Earnings (loss) excluding Identified Items (Non-GAAP) Earnings (loss) excluding Identified Items, are earnings (loss) excluding individually significant non-operational events with, typically, an absolute corporate total earnings impact of at least $250 million in a given quarter. The earnings (loss) impact of an Identified Item for an individual segment in a given quarter may be less than $250 million when the item impacts several segments or several periods. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The Corporation believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Earnings (loss) excluding Identified Items is not meant to be viewed in isolation or as a substitute for net income (loss) attributable to ExxonMobil as prepared in accordance with U.S. GAAP. Upstream (millions of dollars) 2023 2022 2021 U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 4,202 17,106 21,308 11,728 24,751 36,479 3,663 12,112 15,775 Impairments Gain/(loss) on sale of assets Tax-related items Contractual provisions Other Identified Items Earnings (loss) excluding Identified Items (Non-GAAP) (1,978) (686) (2,664) — (3,790) (3,790) (263) (489) (752) 305 184 — — — (126) — — 305 58 — — 299 587 886 — — — (1,415) (1,415) — — 1,380 1,380 — — — — 459 — 459 — (250) (250) — — (1,489) (812) (2,301) 299 (3,238) (2,939) (263) (280) (543) 5,691 17,918 23,609 11,429 27,989 39,418 3,926 12,392 16,318 Energy Products (millions of dollars) Earnings (loss) (U.S. GAAP) Impairments Tax-related items Identified Items 2023 2022 2021 U.S. 6,123 Non-U.S. 6,019 Total 12,142 U.S. 8,340 Non-U.S. 6,626 Total 14,966 U.S. 668 Non-U.S. (1,014) Total (347) — 192 192 — (48) (48) — 144 144 (58) — (58) (216) (410) (626) (274) (410) (684) — — — — — — — — — Earnings (loss) excluding Identified Items (Non-GAAP) 5,931 6,067 11,998 8,398 7,252 15,650 668 (1,014) (347) Chemical Products (millions of dollars) 2023 2022 2021 U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 1,626 11 1,637 2,328 1,215 3,543 3,697 3,292 6,989 Impairments Tax-related items Other Identified Items (21) (273) (294) 53 — 32 — (147) (420) 53 (147) (388) — — — — — — — — — — — — — — — — — — — — — — — — Earnings (loss) excluding Identified Items (Non-GAAP) 1,594 431 2,025 2,328 1,215 3,543 3,697 3,292 6,989 40 FREQUENTLY USED TERMS Specialty Products (millions of dollars) 2023 2022 2021 U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. Total Earnings (loss) (U.S. GAAP) 1,536 1,178 2,714 1,190 1,225 2,415 1,452 1,807 3,259 Impairments Gain/(loss) on sale of assets Tax-related items Other Identified Items Earnings (loss) excluding Identified Items (Non-GAAP) — — 12 — 12 (82) — 5 (28) (105) (82) — 17 (28) (93) — — — — — (40) (40) — — — — — — (40) (40) — 498 — — 498 — 136 — — 136 — 634 — — 634 1,524 1,283 2,807 1,190 1,265 2,455 954 1,672 2,625 Corporate and Financing (millions of dollars) Earnings (loss) (U.S. GAAP) Impairments Gain/(loss) on sale of assets Tax-related items Severance charges Other Identified Items 2023 (1,791) — — 76 — — 76 2022 (1,663) (98) — 324 — 76 302 2021 (2,636) — (12) — (52) — (64) Earnings (loss) excluding Identified Items (Non-GAAP) (1,867) (1,965) (2,572) Corporate Total (millions of dollars) Net income (loss) attributable to ExxonMobil (U.S. GAAP) Impairments Gain/(loss) on sale of assets Tax-related items Severance charges Contractual provisions Other Identified Items Earnings (loss) excluding Identified Items (Non-GAAP) 2023 36,010 (3,040) 305 348 — — (175) (2,562) 38,572 2022 55,740 (4,202) 886 (1,501) — — 1,456 (3,361) 59,101 2021 23,040 (752) 1,081 — (52) (250) — 27 23,013 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. 41 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS Statements related to future events; projections; descriptions of strategic, operating, and financial plans and objectives; statements of future ambitions and plans; and other statements of future events or conditions are forward-looking statements. Similarly, discussion of roadmaps or future plans related to carbon capture, transportation and storage, biofuel, hydrogen, lithium and other future plans to reduce emissions and emission intensity of ExxonMobil, its affiliates, companies it is seeking to acquire and third parties are dependent on future market factors, such as continued technological progress, 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 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 Upstream Permian Basin unconventional operated assets by 2030 and in Pioneer Permian assets by 2035, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, and to reach near-zero methane emissions from operated assets and other methane initiatives; meeting ExxonMobil’s 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, produce biofuels, produce lithium, and use plastic waste as feedstock for advanced recycling; timely granting of governmental permits and certifications; future debt levels and credit ratings; business and project plans, timing, costs, capacities and profitability; resource recoveries and production rates; and planned Denbury and Pioneer integrated benefits, could differ materially due to a number of factors. These include global or regional changes in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and other market factors, economic conditions and seasonal fluctuations that impact prices and differentials for our products; changes in law, regulations, taxes, trade sanctions, or policies, such as government policies supporting lower carbon investment opportunities such as the U.S. Inflation Reduction Act and the ability for projects to qualify for the financial incentives available thereunder, the punitive European taxes on the oil and gas sector and unequal support for different technological methods of emissions reduction or evolving, ambiguous and unharmonized standards imposed by various jurisdictions related to sustainability and GHG reporting; variable impacts of trading activities on our margins and results each quarter; actions of competitors and commercial counterparties; the outcome of commercial negotiations, including final agreed terms and conditions; the ability to access debt markets on favorable terms or at all; the occurrence, pace, rate of recovery and effects of public health crises, including the responses from governments; reservoir performance, including variability and timing factors applicable to unconventional resources; the level and outcome of exploration projects and decisions to invest in future reserves; timely completion of development and other construction projects; final management approval of future projects and any changes in the scope, terms, costs or assumptions of such projects as approved; the actions of government or other actors against our core business activities and acquisitions, divestitures or financing opportunities; war, civil unrest, attacks against the company or industry, and other geopolitical or security disturbances, including disruption of land or sea transportation routes; expropriations, seizure, or capacity, insurance, shipping or export limitations imposed by governments or laws; opportunities for potential acquisitions, investments or divestments and satisfaction of applicable conditions to closing, including timely regulatory approvals; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies; unforeseen technical or operating difficulties and unplanned maintenance; the development and competitiveness of alternative energy and emission reduction technologies; 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. Risk Factors." 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. In addition, historical, current, and forward-looking environmental and other sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making. Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply ExxonMobil views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not ExxonMobil, and their 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. 42 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Actions needed to advance ExxonMobil’s 2030 greenhouse gas emission-reductions plans are incorporated into its medium-term business plans, which are updated annually. The reference case for planning beyond 2030 is based on the Company’s Global Outlook (Outlook) research and publication. The Outlook is reflective of the existing global policy environment and an assumption of increasing policy stringency and technology improvement to 2050. However, the Outlook does not attempt to 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 the Company’s business plans will be updated accordingly. References to projects or opportunities may not reflect investment decisions made by the Corporation or its affiliates. Individual projects or opportunities may advance based on a number of factors, including availability of supportive policy, permitting, technological advancement for cost-effective abatement, insights from the company planning process, and alignment with our partners and other stakeholders. Capital investment guidance in lower-emission investments is based on our corporate plan; however, actual investment levels will be subject to the availability of the opportunity set, public policy support, and focused on returns. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. OVERVIEW The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower- emission fuels, and lithium. ExxonMobil's reportable segments are Upstream, Energy Products, Chemical Products, and Specialty Products. Where applicable, ExxonMobil voluntarily discloses additional U.S., Non-U.S., and regional splits to help investors better understand the company's operations. The company is organized along three businesses – Upstream, Product Solutions, and Low Carbon Solutions, aligning along market-focused value chains. Product Solutions consists of Energy Products, Chemical Products, and Specialty Products. Low Carbon Solutions is included in Corporate and Financing as the business continues to mature through commercialization and deployment of technology. The businesses are supported by centralized service-delivery groups, including Global Projects, Technology and Engineering, Global Operations and Sustainability, as well as three organizations formed in 2023: Global Trading, Supply Chain, and Global Business Solutions. ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new supplies of reliable and affordable lower-emission energy and other critical products. The company’s integrated business model, with significant investments in Upstream, Energy Products, Chemical Products, and Specialty Products segments and Low Carbon Solutions businesses, generally reduces the Corporation’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment decisions are grounded on fundamentals reflected in our long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities which target a low cost of supply to ensure long-term competitiveness. The annual Corporate Plan process establishes the economic assumptions used for evaluating investments and sets operating and capital objectives. The Global Outlook (Outlook), developed annually, is the foundation for the Corporate Plan assumptions. Price ranges for crude oil and natural gas, including price differentials, refinery and chemical margins, volumes, development and operating costs, including greenhouse gas emissions pricing, and foreign currency exchange rates are part of the Corporate Plan assumptions developed annually. Corporate Plan volume projections are based on individual field production profiles, which are also updated at least annually. Major investment opportunities are evaluated over a range of potential market conditions. All major investments are reappraised to ensure we learn from our decisions, and the development and execution of the project. Lessons learned are incorporated in future projects. 43 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS ENVIRONMENT Long-Term Business Outlook ExxonMobil’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends; the scale and variety of energy needs worldwide; capability, practicality and affordability of energy alternatives, including low-carbon solutions; greenhouse gas emission-reduction technologies; and relevant government policies. The Outlook considers these fundamentals to form the basis for the company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the company’s view of global energy demand and supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development. In addition, ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. Included in the range of these scenarios are the Intergovernmental Panel on Climate Change (IPCC) Likely Below 2°C scenarios and three scenarios from the International Energy Agency (IEA): IEA Stated Policies Scenario (STEPS), which reflects a sector-by-sector assessment of current policy in place or announced by governments; IEA Announced Pledges Scenario (APS), which reflects aspirational government targets met on time and in full; and IEA Net Zero Emissions by 2050 Scenario (NZE), which the IEA describes as extremely challenging, acknowledging that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed 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 By 2050, the world’s population is projected to be around 9.7 billion people, or about 2 billion more than in 2021. Coincident with this population increase, the Outlook projects worldwide economic growth to average approximately 2.5 percent per year, with economic output growing by around 110 percent by 2050 compared to 2021. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by almost 15 percent from 2021 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)). 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. Source: ExxonMobil 2023 Global Outlook Under our Outlook, global electricity demand is expected to increase about 80 percent from 2021 to 2050, with developing countries likely to account for over 75 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 2021, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2021 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is expected to increase more than 550 percent, helping total renewables (including other sources, e.g., hydropower) to account for over 80 percent of the increase in electricity supplies through 2050. Total renewables are expected to reach about 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. 44 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy for transportation - including cars, trucks, ships, trains, and airplanes - is expected to increase by over 30 percent from 2021 to 2050. Transportation energy demand is expected to account for more than 60 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak by around 2025, and then decline to levels seen in the early-2000s by 2050, as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of almost 70 percent. By 2050, light-duty vehicles are expected to account for around 15 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in small volumes. Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods will increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as well as the increasing shift toward cleaner forms of energy, such as electricity and natural gas, with coal declining. Demand for oil will continue to grow as a feedstock for industry. As populations grow and prosperity rises, more energy will be needed to power homes, offices, schools, shopping centers, hospitals, etc. Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use will rise about 75 percent between 2021 and 2050. Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2050, global demand for liquid fuels is projected to grow to approximately 110 million oil-equivalent barrels per day, an increase of about 15 percent from 2021. The non-OECD share of global liquid fuels demand is expected to increase to nearly 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by more than 20 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 emerging 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. It is expected to grow the most of any primary energy type from 2021 to 2050, meeting about 40 percent of global energy demand growth. Global natural gas demand is expected to rise nearly 25 percent from 2021 to 2050, with greater than 75 percent of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas - the natural gas found in shale and other tight rock formations - will help meet these needs. In total, about 50 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 two thirds of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific. 45 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Oil and natural gas projected to play a critical role in the global energy mix Primary energy - Quadrillion Btu Percent of primary energy Source: ExxonMobil 2023 Global Outlook Source: ExxonMobil 2023 Global Outlook * Electricity and Hydrogen are secondary energies derived from the primary energies shown **Includes biomass, biofuels, hydropower, and geothermal The world’s energy mix is highly diverse and will remain so through 2050. Oil is expected to continue as the largest source of energy with its share remaining close to 30 percent in 2050. Coal and natural gas are the next largest sources of energy today, with the share of natural gas growing to more than 25 percent by 2050, while the share of coal falls to about half that of natural gas. Nuclear power is projected to grow, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is expected to exceed 20 percent of global energy by 2050, with other renewables (e.g., biomass, hydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind and solar is expected to increase rapidly, growing over 500 percent from 2021 to 2050, when they are projected to be around 10 percent of the world energy mix. Decarbonization of industrial activities will require a suite of nascent or future lower-carbon technologies and supporting policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower- emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Low-carbon 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. 46 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Significant oil and natural gas investment needed to meet projected global demand Projected global oil supply and demand Million barrels per day Projected global natural gas supply and demand Billion cubic feet per day Excludes biofuels; IEA STEPS, IEA APS, and IEA NZE Source: IEA WEO 2023; Global Outlook Source: ExxonMobil 2023 Global Outlook; IPCC Likely Below 2°C Average and Range Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used IEA STEPS, IEA APS, and IEA NZE Source: IEA WEO 2023; Global Outlook Source: ExxonMobil 2023 Global Outlook; IPCC Likely Below 2°C Average and Range Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used To meet projected demand under our Outlook and the IEA's STEPS, 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 is consistent with the successful achievement of the global aggregation of Nationally Determined Contributions (NDCs), submitted by the nations that are signatories to the Paris Agreement, as available at the end of 2022. We have assumed success of these NDCs, despite the 2023 United Nations Environment Programme (UNEP) Emissions Gap Report projecting that the G20 members will fall short of their NDCs. Our Outlook seeks to identify potential impacts of 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. China and other leading non-OECD nations are expected to trail OECD policy initiatives. Nevertheless, 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 NDCs that nations provided around COP 28 in Dubai in 2023, 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. 47 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Progress Reducing Emissions The Corporation’s strategy seeks to maximize the advantages of our scale, business integration, leading technology, functional 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 in the energy transition, bringing to bear these same advantages while retaining investment flexibility across a portfolio of evolving opportunities to grow shareholder value. With advancements in technology, clear and consistent government policies that support needed investments, and the development of market-driven mechanisms, we aim to achieve net-zero Scope 1 and 2 greenhouse gas emissions in our operated assets by 2050. Our net-zero ambition is backed by a comprehensive approach centered on detailed emission-reduction roadmaps for our major operated assets that were completed in 2022. The roadmaps build on the company’s 2030 emission-reduction plans and, notably, include reaching net-zero Scope 1 and 2 emissions in our unconventional Permian Basin operated assets by 2030. Many of the required reduction steps are unaffordable with today's technology and policy support. We continue to update the roadmaps to reflect technology and policy, and to account for the many potential pathways, and the pace of the energy transition. Compared to 2016 levels, our 2030 plans are expected to drive the following reductions: • • • • 20-30 percent reduction in corporate-wide greenhouse gas intensity; 70-80 percent reduction in corporate-wide methane intensity; 40-50 percent reduction in upstream greenhouse gas intensity; and 60-70 percent reduction in corporate-wide flaring intensity. The achievement of these plans is also expected to result in an absolute reduction in corporate-wide greenhouse gas emissions by approximately 20 percent, compared to 2016 levels. Our emission-reduction plans cover Scope 1 and 2 emissions from assets we operate. These plans exclude our recent acquisition of Denbury Inc. The Corporation plans to continue to pursue 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, 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 lower-emission fuels, as well as lithium to supply the global battery and electric vehicle markets. Our customers, many governments, and others recognize our combination of experience, skills, and capabilities that have the potential to help reduce the emissions of others. For example, on the U.S. Gulf Coast, we see an opportunity to create a carbon capture and storage business that will allow industrial customers to reduce their emissions. The recent acquisition of Denbury expands our capabilities in this area, providing ExxonMobil with the largest owned and operated network of CO2 pipelines in the United States, including over 900 miles of pipelines near the largest industrial complexes on the Gulf Coast. Combining Denbury’s assets and our experience expands our ability to help customers in the region reduce their emissions at a lower cost and faster pace. A cost-efficient transportation and storage system has the potential to accelerate carbon capture and storage deployment for both ExxonMobil and our third-party customers. 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. 48 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Recent Business Environment Prior to the COVID-19 pandemic, many companies in the industry invested below the levels needed to maintain or increase production capacity to meet anticipated demand. During the COVID-19 pandemic, this decline in investments accelerated as industry revenue collapsed resulting in underinvestment and supply tightness as demand for petroleum and petrochemical products recovered. In addition, industry rationalization of refining assets resulted in more than 3 million barrels per day of capacity being taken offline. These reductions, along with supply chain constraints and a continuation of demand recovery, led to a steady increase in oil and natural gas prices and refining margins through 2022. Energy markets began to normalize in 2023, down from their 2022 highs. During the first half of 2023, the price of crude oil declined towards the average of the pre-COVID 10-year range (2010-2019), impacted by higher inventory levels. In the second half, crude oil prices increased modestly from strong demand and ongoing actions by OPEC+ oil producers to limit supply. In the first nine months of the year, natural gas prices declined significantly with storage levels increasing above historical averages in the United States and Europe on higher supply and lower demand. In the fourth quarter, natural gas prices improved as higher heating demand in the U.S. and supply interruptions in Europe and Asia brought prices back above the 10-year range. Throughout 2023, refining margins declined on easing supply concerns with stabilization of Russian supply. Strong demand for gasoline and distillate, combined with low inventories, kept refining margins above the 10-year range until the fourth quarter when refining margins settled near the middle of the 10-year range due to lower seasonal demand. Chemical margins remained well below the 10-year range throughout the year as continued demand growth was met with robust supply additions. The general rate of inflation across major countries peaked in 2022, rising from already elevated levels in 2021, due to additional impacts on energy and other commodities from the Russia-Ukraine conflict. Inflation moderated in 2023 as major central banks tightened monetary policy aggressively and global GDP growth slowed. It currently remains higher than the central bank’s inflation target in the U.S. and Eurozone; however, major central banks have recently paused further rate tightening. Meanwhile, there are significant variations across OECD and non-OECD in the pace of change in inflation. The Corporation closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. Organizational changes implemented versus 2019, including $2.3 billion of savings during 2023, through over the past several years enabled the Corporation to capture $9.7 billion of structural cost savings increased operational efficiencies and reduced staffing costs. The company sees additional opportunities in areas such as supply chain efficiency, improved maintenance and turnarounds, modernized data management, and simplified business processes. These savings are key drivers for further improving the earnings power of the Corporation. (1) (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 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 2023 were approximately $2.0 billion, and its share of combined oil and gas production was approximately 275 thousand oil-equivalent barrels per day. Additional European Taxes on the Energy Sector On October 6, 2022, European Union (“EU”) Member States adopted an EU Council Regulation which, along with other measures, introduced a new tax described as an emergency intervention to address high energy prices. This regulation imposed a mandatory tax on certain companies active in the crude petroleum, coal, natural gas, and refinery sectors. The regulation required Member States to levy a minimum 33 percent tax on in-scope companies’ 2022 and/or 2023 “surplus profits", defined in the regulation as taxable profits exceeding 120 percent of the annual average profits during the 2018-2021 period. EU Member States were required to implement the tax, or an equivalent national measure, by December 31, 2022. The enactment of these regulations by Member States resulted in an after-tax charge of approximately $1.8 billion to the Corporation’s fourth-quarter 2022 results and approximately $0.2 billion in 2023, mainly reflected in the line “Income tax expense (benefit)” on the Consolidated Statement of Income. Remaining cash payments are anticipated in the first half of 2024. 49 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS RESULTS Upstream ExxonMobil has a diverse growth portfolio of exploration and development opportunities, which allows the Corporation to be selective in our investments, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s strategies guide our global Upstream business, including capturing material and accretive opportunities to continually high-grade the resource portfolio, selectively developing attractive oil and natural gas resources, developing and applying high-impact technologies, and pursuing productivity and efficiency gains as well as a reduction in greenhouse gas emissions. These strategies are underpinned by a relentless focus on operational excellence, development of our employees, and investment in the communities in which we operate. The Upstream capital program continues to prioritize low cost-of-supply opportunities. ExxonMobil has a strong pipeline of development projects including continued growth in Guyana and the Permian Basin, as well as LNG expansion opportunities in Qatar, Mozambique, Papua New Guinea, and the United States. As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix and in the type of opportunities from which volumes are produced. Based on the current investment plans and merger with Pioneer, the proportion of oil-equivalent production from the Americas is generally expected to increase over the next several years. Currently about half of the Corporation's global production comes from unconventional, deepwater, and LNG resources. This proportion is generally expected to grow. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, the impact of fiscal and commercial terms, asset sales, weather events, price effects on production sharing contracts, changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment, international trade patterns and relations, and other factors described in "Item 1A. Risk Factors". 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 and other large government resource owners, alternative energy sources, and other factors. Key Recent Events Guyana: Exploration success continued with four additional discoveries on the Stabroek Block in 2023. Prosperity, the third floating production, storage and offloading (FPSO) vessel, started production at the Payara development on the Stabroek Block in November 2023 and reached nameplate capacity in January 2024, well ahead of schedule. Liza Destiny and Liza Unity FPSO vessels continued to produce above nameplate capacity. The combined gross production from the three operating vessels exceeded 390 thousand barrels of oil per day (kbd) in 2023 and nearly 440 kbd in the fourth quarter of 2023. Yellowtail and Uaru, the fourth and fifth developments on the Block, are progressing on schedule and will each initially produce approximately 250 kbd. We anticipate six FPSO vessels will be in operation on the Stabroek Block by year-end 2027. We are working with the government of Guyana to secure regulatory approvals for a sixth project at Whiptail. Permian: Production volumes averaged about 610 thousand oil-equivalent barrels per day (koebd) in 2023, approximately 60 koebd higher than the previous year. ExxonMobil operations continue to deliver industry-leading capital efficiency and cost performance by leveraging scale, integration, and technology. Examples include best-in-class laterals, up to four miles, which will result in fewer wells and a smaller surface footprint. ExxonMobil remains on track to achieve industry-leading plans of net-zero Scope 1 and 2 greenhouse gas emissions from our operated unconventional operations in the Permian Basin by 2030. In 2023, operation teams sustained zero routine flaring , completed the program to eliminate over 6,000 pneumatic venting devices, increased electrification of operations, signed long-term agreements to use lower-carbon wind power, and expanded continuous emissions monitoring programs. In October 2023, ExxonMobil announced a definitive agreement to acquire Pioneer in an all-stock transaction valued at $59.5 billion , more than doubling our Permian footprint. The transaction represents an opportunity to deliver leading capital efficiency and cost performance as well as increase production by combining Pioneer's large scale, contiguous, high-quality undeveloped Midland acreage with ExxonMobil's Permian resource development approach. In addition to increasing production, we plan to pull forward Pioneer's Net Zero ambition by 15 years, from 2050 to 2035. (1) (2) LNG: ExxonMobil continued work on LNG growth projects in 2023. The Papua New Guinea LNG project progressed front-end engineering and design work in support of a final investment decision anticipated in 2024. Optimization of the Mozambique onshore LNG plans for Rovuma LNG to develop the gas resource continued, working to ensure the right conditions are met for full funding, including a sustainable and secure operating environment and a design that will achieve long-term project competitiveness. Construction continues on the Golden Pass LNG project with Train 1 mechanical completion expected at the end of 2024 with first LNG production in the first half of 2025. (1) References to routine flaring herein are consistent with the World Bank's Zero Routine Flaring Reduction Partnership's (GGFRP) principle of routine flaring, and excludes safety and non-routine flaring. Based on the October 5, 2023, closing price for ExxonMobil shares and the fixed exchange rate of 2.3234 per Pioneer share. (2) 50 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Upstream Financial Results (millions of dollars) Earnings (loss) (U.S. GAAP) United States Non-U.S. Total Identified Items (1) United States Non-U.S. Total Earnings (loss) excluding Identified Items United States (1) (Non-GAAP) Non-U.S. Total (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 2023 Upstream Earnings Factor Analysis (millions of dollars) 2023 2022 2021 4,202 17,106 21,308 (1,489) (812) (2,301) 5,691 17,918 23,609 11,728 24,751 36,479 299 (3,238) (2,939) 11,429 27,989 39,418 3,663 12,112 15,775 (263) (280) (543) 3,926 12,392 16,318 Price – Lower realizations decreased earnings by $14,290 million reflecting lower gas prices and crude price moderation with growing liquids supply to address record demand, and unfavorable mark-to-market impacts of $2,380 million. Volume/Mix – Improved portfolio mix increased earnings by $970 million. The earnings benefit from the advantaged volume growth primarily in Guyana and the Permian more than offset the impacts from divestments, the Russia expropriation, and higher government-mandated curtailments. Other – All other items decreased earnings by $100 million on increased activity and inflation, partly offset by positive foreign exchange effects and structural efficiencies. (1) Identified Items – 2022 $(2,939) million loss mainly driven by the Russia expropriation $(2,185) million and impacts from additional European taxes $(1,415) million, partly offset by gains of $886 million on the sale of the Romania, U.S. Barnett Shale, and XTO Energy Canada assets; 2023 $(2,301) million loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California. (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 51 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2022 Upstream Earnings Factor Analysis (millions of dollars) Price – Higher realizations increased earnings by $21,290 million reflecting tight supply and recovering demand, and favorable mark-to-market impacts of $2,800 million. Volume/Mix – Volume and mix effects decreased earnings by $110 million. The earnings benefit from volume growth in Guyana and the Permian was offset by the volume loss from divestments, the Russia expropriation, and other impacts including weather-related downtime. Other – All other items decreased earnings by $880 million as strong cost control partly offset impacts from inflation and increased activity. (1) Identified Items – 2021 $(543) million loss as a result of impairments of $(752) million and contractual provisions of $(250) million, partly offset by a $459 million gain from the U.K Central and Northern North Sea divestment; 2022 $(2,939) million loss mainly driven by the Russia expropriation $(2,185) million and impacts from additional European taxes $(1,415) million, partly offset by gains of $886 million on the sale of the Romania, U.S. Barnett Shale, and XTO Energy Canada assets. (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. Upstream Operational Results Net production of crude oil, natural gas liquids, bitumen and synthetic oil (thousands of barrels daily) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Worldwide Net natural gas production available for sale (millions of cubic feet daily) United States Canada/Other Americas Europe Africa Asia Australia/Oceania Worldwide Oil-equivalent production (thousands of oil-equivalent barrels daily) (2) (2) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. 52 2023 2022 2021 803 664 4 221 721 36 776 588 4 238 705 43 721 560 22 248 695 43 2,449 2,354 2,289 2,311 2,551 2,746 96 414 125 3,490 1,298 7,734 3,738 148 667 71 3,418 1,440 8,295 3,737 195 808 43 3,465 1,280 8,537 3,712 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Upstream Additional Information (thousands of barrels daily) Volumes Reconciliation (Oil-equivalent production) (1) Prior Year Entitlements - Net Interest Entitlements - Price / Spend / Other Government Mandates (2) Divestments Growth / Other (2) Current Year 2023 2022 3,737 3,712 (24) 56 (28) (114) 111 3,738 (44) (34) 71 (71) 103 3,737 (1) (2) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. In the Volumes Reconciliation for 2022, -9 KOEBD has been recategorized from Growth / Other to Government Mandates following additional analysis in 2023 related to Groningen production limits. 2023 versus 2022 2023 production of 3.7 million oil-equivalent barrels per day is in line with 2022. Permian and Guyana production grew by more than 120 thousand oil-equivalent barrels per day, more than offsetting impacts from divestments. Excluding the impacts from entitlements, divestments, and higher government-mandated curtailments, net production grew by 111 thousand oil-equivalent barrels per day. 2022 versus 2021 2022 production of 3.7 million oil-equivalent barrels per day increased 25 thousand barrels per day from 2021. Excluding the impacts from entitlements, Russia expropriation, divestments, and eased government-mandated curtailments, net production grew by 103 thousand oil-equivalent barrels per day driven by Permian and Guyana. Listed below are descriptions of ExxonMobil’s volumes reconciliation factors, 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 factors. These factors 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 factors. These factors 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 factors 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 factors comprise all other operational and non-operational factors not covered by the above definitions that may affect volumes attributable to ExxonMobil. Such factors 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. 53 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy Products ExxonMobil's Energy Products is one of the largest, most integrated businesses of its kind among international oil companies, with significant representation across the entire fuels value chain including refining, logistics, trading, and marketing. This segment includes the fuels and aromatics value chains and catalysts and licensing. With the largest refining footprint among international oil companies, ExxonMobil’s Energy Products earnings are closely tied to industry refining margins. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials and the market prices for the products produced. Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g. New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather, and political considerations. While industry refining margins significantly impact Energy Products earnings, strong operations performance, product mix optimization, and disciplined cost control are also critical to strong financial performance. In 2023, refining margins remained above the pre-COVID 10-year historical range (2010–2019) but started to normalize from their 2022 highs. Continued strong margins were supported by gasoline and distillate demand growth and relatively low inventory levels. Refining margins will remain volatile with changes in global factors including geopolitical developments; demand growth; recession fears; inventory levels; and refining capacity utilizations, additions and rationalizations. Key Recent Events Capacity additions: The company started-up its Beaumont Refinery expansion in February 2023, two months early, and reached nameplate crude distillation capacity of 250 thousand barrels per day in March. Strathcona Renewable Diesel project: In January 2023, ExxonMobil and its affiliates fully funded a project at Strathcona refinery to use low-carbon hydrogen, locally- sourced and grown feedstocks, and our proprietary catalyst to produce 20 thousand barrels of renewable diesel per day that will help reduce greenhouse gas emissions. Singapore Resid Upgrade project: Progressed project with expected start-up in 2025, which will leverage two proprietary technologies to upgrade fuel oil to Group II lubes and diesel, further strengthening ExxonMobil’s competitiveness. Billings divestment: In June 2023, ExxonMobil divested the Billings Refinery and select midstream assets in Montana and Washington. Esso Thailand divestment: In August 2023, ExxonMobil sold its interest in Esso Thailand, which included the Sriracha Refinery, select distribution terminals, and a network of Esso-branded retail stations. Italy Fuels divestment: In October 2023, ExxonMobil sold its interest in the Trecate Refinery joint venture, select midstream assets, and the fuels marketing business. Miro Refinery sale: In October 2023, ExxonMobil reached an agreement to sell its interest in the Miro refinery located in Karlsruhe, Germany, and we expect the transaction to close in 2024. 54 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy Products Financial Results (millions of dollars) Earnings (loss) (U.S. GAAP) United States Non-U.S. Total Identified Items (1) United States Non-U.S. Total Earnings (loss) excluding Identified Items United States (1) (Non-GAAP) Non-U.S. Total (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. Due to rounding, numbers presented may not add up precisely to the totals indicated. 2023 Energy Products Earnings Factor Analysis (millions of dollars) 2023 2022 2021 6,123 6,019 12,142 8,340 6,626 14,966 668 (1,014) (347) 192 (48) 144 (58) (626) (684) — — — 5,931 6,067 11,998 8,398 7,252 15,650 668 (1,014) (347) Margins – Decreased earnings by $3,190 million as industry refining margins declined from 2022 highs, partially offset by stronger trading and marketing margins. Volume/Mix – Increased earnings by $80 million reflecting improved reliability and higher throughput mainly driven by the Beaumont expansion, partially offset by higher planned maintenance and divestments. Other – Decreased earnings by $540 million due to higher planned maintenance expenses and Beaumont project activities. Identified Items – 2022 $(684) million loss was primarily as a result of impairments and unfavorable tax items. 2023 $144 million gain was driven by favorable tax effects partially offset by additional European taxes on the energy sector. (1) (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 55 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2022 Energy Products Earnings Factor Analysis (millions of dollars) Margins – Increased earnings by $14,360 million as industry refining conditions significantly improved from increased demand and low inventories, as well as stronger trading and marketing margins. Volume/Mix – Increased earnings by $1,060 million reflecting improved product yields and higher throughput. Other – Increased earnings by $570 million due to favorable foreign exchange and year-end inventory effects. Identified Items – 2022 $(684) million loss was driven by additional European taxes on the energy sector and impairments. (1) (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. Energy Products Operational Results (thousands of barrels daily) Refinery throughput United States Canada Europe Asia Pacific Other Worldwide Energy Products sales United States Non-U.S. (2) Worldwide Gasoline, naphthas Heating oils, kerosene, diesel Aviation fuels Heavy fuels Other energy products Worldwide (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 56 2023 2022 2021 1,848 407 1,166 498 149 4,068 2,633 2,828 5,461 2,288 1,795 336 214 829 1,702 418 1,192 539 179 4,030 2,426 2,921 5,347 2,232 1,774 338 235 768 1,623 379 1,210 571 162 3,945 2,267 2,863 5,130 2,158 1,749 220 269 734 5,461 5,347 5,130 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Chemical Products ExxonMobil is a leading global manufacturer and marketer of petrochemicals that support modern living. Chemical Products help meet society’s essential needs by providing a wide range of innovative products efficiently and responsibly. The company is uniquely positioned with a combination of industry-leading scale, integration, and proprietary technology, which are fundamental to producing affordable products that are more sustainable, use less material, save energy, and reduce waste. These competitive advantages are underpinned by operational excellence, advantaged investments, and cost discipline. This segment includes olefins, polyolefins, and intermediates. Over the long term, worldwide demand for chemicals is expected to grow faster than the economy, driven by global population growth, an expanding middle class, and improving living standards. Chemical Products integration with refineries, performance product mix, and project execution capability improves returns on investments across a range of market environments. In 2023, chemical industry margins remained bottom-of-cycle, below the pre-COVID 10-year historical range (2010-2019), as capacity exceeded demand growth. The company optimized production across our global footprint to profitably meet customer demand. Our earnings benefited from the North American feed and energy advantage, strong reliability, and higher performance products sales. Key Recent Events Performance Polymers expansion: ExxonMobil successfully started up a new performance polymers line in Baytown, Texas. This 400 thousand metric tons per year unit will make high-performance propylene and ethylene plastomers branded Vistamaxx™ and Exact™. These materials can be used to make better automotive parts, construction materials, personal care products, and solar panels. Linear Alpha Olefins production: ExxonMobil successfully started up a new 350 thousand metric tons per year linear alpha olefins unit in Baytown, Texas. The unit will produce a full range of alpha olefin products that are essential to our Specialty and Chemical Products businesses. This marks ExxonMobil's entry into the linear alpha olefins market via Elevexx™ branded products. These materials can be used in plastic packaging, high-performing engine and industrial oils, and other applications. Future capacity additions: ExxonMobil is investing in a petrochemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province, which is a significant step in growing our global manufacturing footprint and will be the first 100 percent foreign-owned petrochemical complex built in China. The facility will be focused on producing our unique high-performance polyethylene and polypropylene products. When completed, the complex will have three polyethylene and two polypropylene production lines for a combined capacity of over 2.5 million metric tons per year. This capacity will more efficiently serve China’s domestic demand, which is currently being met with imports. 57 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Chemical Products Financial Results (millions of dollars) Earnings (loss) (U.S. GAAP) United States Non-U.S. Total Identified Items (1) United States Non-U.S. Total Earnings (loss) excluding Identified Items United States (1) (Non-GAAP) Non-U.S. Total (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 2023 Chemical Products Earnings Factor Analysis (millions of dollars) 2023 2022 2021 1,626 11 1,637 32 (420) (388) 1,594 431 2,025 2,328 1,215 3,543 — — — 2,328 1,215 3,543 3,697 3,292 6,989 — — — 3,697 3,292 6,989 Margins – Lower margins decreased earnings by $870 million due to bottom-of-cycle price conditions as industry supply additions continued to outpace demand growth. Volume/Mix – Unfavorable sales mix decreased earnings by $160 million, partially offset by new volumes from strategic projects. Other – All other items decreased earnings by $490 million, primarily as a result of higher expenses from scheduled maintenance and production capacity additions. Identified Items – 2023 $(388) million loss was primarily driven by impairments. (1) (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 58 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2022 Chemical Products Earnings Factor Analysis (millions of dollars) Margins – Lower margins decreased earnings by $3,030 million with normalization of regional prices during the year, increased supply, and bottom-of-cycle conditions in Asia Pacific. Volume/Mix – Product mix decreased earnings by $170 million. Other – All other items decreased earnings by $250 million primarily as a result of higher expenses from production capacity additions, and foreign exchange effects from a stronger U.S. dollar. Chemical Products Operational Results (thousands of metric tons) Chemical product sales United States (1) Non-U.S. Worldwide (1) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 59 2023 2022 2021 6,779 12,603 19,382 7,270 11,897 19,167 7,017 12,126 19,142 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Specialty Products ExxonMobil Specialty Products is a combination of business units that manufacture and market a range of performance products including high-quality lubricants, basestocks, waxes, synthetics, elastomers, and resins. Leveraging ExxonMobil’s proprietary technologies, Specialty Products focuses on providing performance products that help customers improve efficiency in the transportation and industrial sectors. Specialty Products is well-positioned to help meet growth in lubricants demand through advantaged projects that leverage ExxonMobil's integration, technology, and world- TM class brands, such as Mobil 1 . In 2023, Specialty Products continued to deliver strong earnings from our portfolio of high-value products and brand market position. Key Recent Events Singapore Resid Upgrade project: Progressed project with expected start-up in 2025, which will leverage two proprietary technologies to upgrade fuel oil to Group II lubes and diesel, further strengthening ExxonMobil’s position as the largest basestock producer in the world. 60 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Specialty Products Financial Results (millions of dollars) Earnings (loss) (U.S. GAAP) United States Non-U.S. Total Identified Items (1) United States Non-U.S. Total Earnings (loss) excluding Identified Items United States (1) (Non-GAAP) Non-U.S. Total (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. Due to rounding, numbers presented may not add up precisely to the totals indicated. 2023 Specialty Products Earnings Factor Analysis (millions of dollars) 2023 2022 2021 1,536 1,178 2,714 12 (105) (93) 1,524 1,283 2,807 1,190 1,225 2,415 — (40) (40) 1,190 1,265 2,455 1,452 1,807 3,259 498 136 634 954 1,672 2,625 Margins – Stronger margins increased earnings by $440 million driven by high-value products and lower feed costs. Volume/Mix – Lower volumes decreased earnings by $120 million on weaker global demand. Other – All other items increased earnings by $30 million as a result of positive year-end inventory effects and favorable tax impacts, partially offset by unfavorable foreign exchange effects. Identified Items (1) – 2022 $(40) million loss from impairments; 2023 $(93) million loss mainly from impairments. (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 61 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2022 Specialty Products Earnings Factor Analysis (millions of dollars) Margins – Margins decreased earnings by $220 million driven by higher feed costs and energy prices. Volume/Mix – Higher volumes increased earnings by $20 million on robust demand. Other – All other items increased earnings by $30 million primarily as a result of positive year-end inventory effects, offset by increased expenses from higher maintenance and inflation, and unfavorable foreign exchange impacts. Identified Items – 2021 $634 million gain resulted from the Santoprene divestment; 2022 $(40) million loss from impairments. (1) (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. Specialty Products Operational Results (thousands of metric tons) Specialty Products sales United States (2) Non-U.S. Worldwide (2) Data reported net of purchases/sales contracts with the same counterparty. Due to rounding, numbers presented may not add up precisely to the totals indicated. 62 2023 2022 2021 1,962 5,635 7,597 2,049 5,762 7,810 1,943 5,723 7,666 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Corporate and Financing Corporate and Financing is comprised of corporate activities that support ExxonMobil's operating segments and Low Carbon Solutions business. Corporate activities include general administrative support functions, financing, and insurance activities. Low Carbon Solutions activities will be included in Corporate and Financing until the business is established with a material level of assets and customer contracts. On November 2, 2023, the Corporation acquired Denbury, a developer of carbon capture, utilization and storage solutions and enhanced oil recovery producing assets. This acquisition expands the Corporation’s Low Carbon Solutions capabilities. See Note 21 of the Condensed Consolidated Financial Statements for additional information. Corporate and Financing Financial Results (millions of dollars) Earnings (loss) (U.S. GAAP) Identified Items (1) Earnings (loss) excluding Identified Items (1) (Non-GAAP) (1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. 2023 2022 2021 (1,791) 76 (1,867) (1,663) 302 (1,965) (2,636) (64) (2,572) 2023 2022 Corporate and Financing expenses were $1,791 million in 2023 compared to $1,663 million in 2022, with the increase mainly due to the absence of prior year favorable tax-related items, partly offset by lower financing costs. Corporate and Financing expenses were $1,663 million in 2022 compared to $2,636 million in 2021, with the decrease mainly due to lower pension-related expenses, favorable one-time tax impacts, and lower financing costs. 63 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Cash (millions of dollars) Net cash provided by/(used in) Operating activities Investing activities Financing activities Effect of exchange rate changes Increase/(decrease) in cash and cash equivalents 2023 2022 2021 55,369 (19,274) (34,297) 105 1,903 76,797 (14,742) (39,114) (78) 22,863 48,129 (10,235) (35,423) (33) 2,438 Total cash and cash equivalents (December 31) 31,568 29,665 6,802 Total cash and cash equivalents were $31.6 billion at the end of 2023, up $1.9 billion from the prior year. The major sources of funds in 2023 were net income including noncontrolling interests of $37.4 billion, the adjustment for the noncash provision of $20.6 billion for depreciation and depletion, proceeds from asset sales of $4.1 billion, and other investing activities of $1.6 billion. The major uses of funds included spending for additions to property, plant and equipment of $21.9 billion; dividends to shareholders of $14.9 billion; the purchase of ExxonMobil stock of $17.7 billion; additional investments and advances of $3.0 billion; and a change in working capital of $4.3 billion. Total cash and cash equivalents were $29.7 billion at the end of 2022, up $22.9 billion from the prior year. The major sources of funds in 2022 were net income including noncontrolling interests of $57.6 billion, the adjustment for the noncash provision of $24.0 billion for depreciation and depletion, proceeds from asset sales of $5.2 billion, and other investing activities of $1.5 billion. The major uses of funds included spending for additions to property, plant and equipment of $18.4 billion; dividends to shareholders of $14.9 billion; the purchase of ExxonMobil stock of $15.2 billion; a debt reduction of $7.2 billion; and additional investments and advances of $3.1 billion. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. On December 31, 2023, the Corporation had undrawn short-term committed lines of credit of $0.3 billion and undrawn long- term lines of credit of $1.3 billion. To support cash flows in future periods, the Corporation will need to continually find or acquire and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields to eventually produce at declining rates for the remainder of their economic life. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. In particular, the Corporation’s key tight-oil plays have higher initial decline rates which tend to moderate over time. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms. The Corporation has long been successful at mitigating the effects of natural field decline through disciplined investments in quality opportunities and project execution. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of investments that may vary depending on the oil and gas price environment; and international trade patterns and relations. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to "Item 1A. Risk Factors" for a more complete discussion of risks. The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2023 were $26.3 billion, reflecting the Corporation’s continued active investment program. The Corporation plans to invest in the range of $23 billion to $25 billion in 2024. 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. 64 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Corporation, as part of its ongoing asset management program, continues to evaluate its mix of assets for potential upgrade. Because of the ongoing nature of this program, dispositions will continue to be made from time to time which will result in either gains or losses. Additionally, the Corporation continues to evaluate opportunities to enhance its business portfolio through acquisitions of assets or companies, and enters into such transactions from time to time. Key criteria for evaluating acquisitions include strategic fit, cost 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 2023 Cash provided by operating activities totaled $55.4 billion in 2023, $21.4 billion lower than 2022. The major source of funds was net income including noncontrolling interests of $37.4 billion, a decrease of $20.2 billion. The noncash provision for depreciation and depletion was $20.6 billion, down $3.4 billion from the prior year. The adjustment for the net gain on asset sales was $0.5 billion, a decrease of $0.5 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $0.5 billion, compared to a reduction of $2.4 billion in 2022. Changes in operational working capital, excluding cash and debt, decreased cash in 2023 by $4.3 billion. 2022 Cash provided by operating activities totaled $76.8 billion in 2022, $28.7 billion higher than 2021. The major source of funds was net income including noncontrolling interests of $57.6 billion, an increase of $34.0 billion. The noncash provision for depreciation and depletion was $24.0 billion, up $3.4 billion from the prior year. The adjustment for the net gain on asset sales was $1.0 billion, a decrease of $0.2 billion. The adjustment for dividends received less than equity in current earnings of equity companies was a reduction of $2.4 billion, compared to a reduction of $0.7 billion in 2021. Changes in operational working capital, excluding cash and debt, decreased cash in 2022 by $0.2 billion. Cash Flow from Investing Activities 2023 Cash used in investing activities netted to $19.3 billion in 2023, $4.5 billion higher than 2022. Spending for property, plant and equipment of $21.9 billion increased $3.5 billion from 2022. Proceeds from asset sales and returns of investments of $4.1 billion compared to $5.2 billion in 2022. Additional investments and advances were $0.1 billion lower in 2023, while proceeds from other investing activities including collection of advances increased by $0.1 billion. 2022 Cash used in investing activities netted to $14.7 billion in 2022, $4.5 billion higher than 2021. Spending for property, plant and equipment of $18.4 billion increased $6.3 billion from 2021. Proceeds from asset sales and returns of investments of $5.2 billion compared to $3.2 billion in 2021. Additional investments and advances were $0.3 billion higher in 2022, while proceeds from other investing activities including collection of advances were $1.5 billion during the year. 65 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Cash Flow from Financing Activities 2023 Cash used in financing activities was $34.3 billion in 2023, $4.8 billion lower than 2022. Dividend payments on common shares increased to $3.68 per share from $3.55 per share and totaled $14.9 billion. Exxon Mobil Corporation continued its share repurchase program for up to $50 billion in shares through 2024, including the purchase of 162 million shares at a book value of $17.5 billion in 2023. In its 2023 Corporate Plan Update released December 6, 2023, the Corporation stated that after the Pioneer transaction closes, the go-forward share repurchase program pace is expected to increase to $20 billion annually through 2025, assuming reasonable market conditions. The stock repurchase program does not obligate the company to acquire any particular amount of common stock, and it may be discontinued or resumed at any time. The timing and amount of shares actually repurchased in the future will depend on market, business, and other factors. 2022 Cash used in financing activities was $39.1 billion in 2022, $3.7 billion higher than 2021. Dividend payments on common shares increased to $3.55 per share from $3.49 per share and totaled $14.9 billion. During 2022, the Corporation utilized cash to reduce debt by $7.2 billion. During 2022, Exxon Mobil Corporation restarted its share repurchase program for up to $50 billion in shares through 2024, including the purchase of 162 million shares at a cost of $15 billion in 2022. Contractual Obligations The Corporation has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs. These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, take-or-pay and unconditional purchase obligations, and firm capital commitments. See Notes 9, 11, 14 and 17 for information related to asset retirement obligations, leases, long-term debt and pensions, respectively. In addition, the Corporation also enters into commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. These commitments are not meaningful in assessing liquidity and cash flow, because the purchases will be offset in the same periods by cash received from the related sales transactions. Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. These obligations mainly pertain to pipeline, manufacturing supply and terminal agreements. The total obligation at year-end 2023 for take-or-pay and unconditional purchase obligations was $44.3 billion. Cash payments expected in 2024 and 2025 are $4.1 billion and $4.3 billion, respectively. Guarantees The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2023 for guarantees relating to notes, loans and performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. Where it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence. Guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 66 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Financial Strength On December 31, 2023, the Corporation had total unused short-term committed lines of credit of $0.3 billion (Note 6) and total unused long-term committed lines of credit of $1.3 billion (Note 14). The table below shows the Corporation’s consolidated debt to capital ratios. (percent) Debt to capital Net debt to capital 2023 16.4 4.5 2022 16.9 5.4 2021 21.4 18.9 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. Stronger industry conditions in 2021 and 2022 enabled the Corporation to strengthen the balance sheet and return debt to pre-pandemic levels by the end of 2022. The Corporation reduced debt by $6.5 billion in 2022. The total debt level remained relatively flat in 2023, ending the year at $41.6 billion. Litigation and Other Contingencies As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 16 for additional information on legal proceedings and other contingencies. 67 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CAPITAL AND EXPLORATION EXPENDITURES Capital and exploration expenditures (Capex) represent the combined total of additions at cost to property, plant and equipment, and exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value of ExxonMobil shares used to acquire assets, and depreciation on the cost of exploration support equipment and facilities recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures. (millions of dollars) Upstream (including exploration expenses) Energy Products Chemical Products Specialty Products Other Total 2023 2022 U.S. Non-U.S. Total U.S. Non-U.S. Total 8,813 1,195 751 63 622 10,948 1,580 1,962 391 — 19,761 2,775 2,713 454 622 6,968 1,351 1,123 46 59 10,034 1,059 1,842 222 — 17,002 2,410 2,965 268 59 11,444 14,881 26,325 9,547 13,157 22,704 Capex in 2023 was $26.3 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation plans to invest in the range of $23 billion to $25 billion in 2024. Included in the 2024 capital spend range is $10.5 billion of firm capital commitments. An additional $9.2 billion of firm capital commitments have been made for years 2025 and beyond. Actual spending could vary depending on the progress of individual projects and property acquisitions. Upstream spending of $19.8 billion in 2023 was up 16 percent from 2022, reflecting higher spend in the U.S. Permian Basin and on advantaged projects in Guyana. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The percentage of proved developed reserves was 63 percent of total proved reserves at year-end 2023, and has been over 60 percent for the last ten years. Capital investments in the three Product Solutions businesses totaled $5.9 billion in 2023, an increase of $0.3 billion from 2022, reflecting higher global project spending. Key investments in 2023 included the China petrochemical complex and Singapore resid upgrade project. Other spend of $0.6 billion primarily reflects investments in the Low Carbon Solutions business which focused on carbon capture and storage, lithium, and hydrogen. TAXES 2023 (millions of dollars) Income taxes Effective income tax rate Total other taxes and duties Total 2023 2022 15,429 20,176 33% 32,191 47,620 33% 31,455 51,631 2021 7,636 31% 32,955 40,591 Total taxes on the Corporation’s income statement were $47.6 billion in 2023, a decrease of $4.0 billion from 2022. Income tax expense, both current and deferred, was $15.4 billion compared to $20.2 billion in 2022. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This is flat compared to 2022, with higher effective rates from various jurisdictions offset by a lower impact from additional European taxes on the energy sector. Total other taxes and duties of $32.2 billion in 2023 increased $0.7 billion. 2022 Total taxes on the Corporation’s income statement were $51.6 billion in 2022, an increase of $11.0 billion from 2021. Income tax expense, both current and deferred, was $20.2 billion compared to $7.6 billion in 2021. 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 compared to 31 percent in the prior year driven by impacts from additional European taxes on the energy sector. Total other taxes and duties of $31.5 billion in 2022 decreased $1.5 billion. 68 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ENVIRONMENTAL MATTERS Environmental Expenditures (millions of dollars) Capital expenditures Other expenditures Total 2023 2,799 4,336 7,135 2022 1,864 3,835 5,699 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 2023 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $7.1 billion, of which $4.3 billion were included in expenses with the remainder in capital expenditures. As the Corporation progresses its emission- reduction plans, worldwide environmental expenditures are expected to increase to approximately $9.7 billion in 2024, with capital expenditures expected to account for approximately 47 percent of the total. Costs for 2025 are anticipated to increase to approximately $10.2 billion, with capital expenditures expected to account for approximately 51 percent of the total. 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 2023 for environmental liabilities were $208 million ($185 million in 2022), and the balance sheet reflects liabilities of $701 million as of December 31, 2023, and $730 million as of December 31, 2022. MARKET RISKS Worldwide Average Realizations Crude oil and NGL ($ per barrel) Natural gas ($ per thousand cubic feet) (1) (1) Consolidated subsidiaries. 2023 69.85 4.26 2022 87.25 7.48 2021 61.89 4.33 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 2024, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $525 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide average gas realization would have approximately a $130 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period. In the very competitive petroleum and petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage. 69 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information on intersegment revenue. Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC 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 that 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, 2023 and 2022, or results of operations for the years ended 2023, 2022, and 2021. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position, results of operations or liquidity exist as a result of the derivatives described in Note 13. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. 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. 70 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 business opportunities including carbon capture and storage, hydrogen, lower-emission fuels and lithium. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1. Oil and Natural Gas Reserves The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, 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. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. 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. 71 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from unconventional operated assets in the Permian Basin. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. While third-party scenarios may be used for these purposes, they are not used as a basis for developing future cash flows for impairment assessments. As part of the Corporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy. Fair Value of Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. 72 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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. 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. In early 2022, in response to Russia’s military action in Ukraine, the Corporation announced that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first quarter 2022 results included after-tax charges of $3.0 billion representing the impairment of its Upstream operations related to Sakhalin. (Refer to Note 2 for further information on Russia.) During 2022, other after-tax impairment charges of $1.6 billion and $0.3 billion were recognized in Upstream and Energy Products, respectively. In 2021, largely as a result of changes to Upstream development plans, the Corporation recognized after-tax impairment charges of approximately $1 billion. Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets. For further information regarding impairments in equity method investments, property, plant, and equipment, and suspended wells, refer to Notes 7, 9, and 10, respectively. Asset Retirement Obligations The Corporation is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. See Note 9 for further information regarding asset retirement obligations. Suspended Exploratory Well Costs The Corporation continues capitalization of exploratory well costs when it has found a sufficient quantity of reserves to justify completion as a producing well and 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. Assessing whether the Corporation is making sufficient progress on a project requires careful consideration of the facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10. 73 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Pension Benefits The Corporation and its affiliates sponsor about 75 defined benefit (pension) plans in 40 countries. The Pension and Other Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets, and pension expense. Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets. For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes. The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate. Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2023 was 5.2 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 5 percent and 6 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $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 16, for purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16. Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement. The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19. 74 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, 2023. The Corporation excluded Denbury Inc. from our assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the Corporation in a business combination during 2023. Total assets and total revenues of Denbury Inc., a wholly owned subsidiary, represent two percent and less than one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2023, as stated in their report included in the Financial Section of this report. Darren W. Woods Chief Executive Officer Kathryn A. Mikells Senior Vice President and Chief Financial Officer Len M. Fox Vice President and Controller (Principal Accounting Officer) 75 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, 2023 and 2022, 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, 2023, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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 the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Denbury Inc. from its assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the Company in a business combination during 2023. We have also excluded Denbury Inc. from our audit of internal control over financial reporting. Denbury Inc. is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent two percent and less than one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. 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. 76 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, 9 and 18 to the consolidated financial statements, the Corporation's consolidated upstream property, plant and equipment (PP&E), net balance was $148.2 billion as of December 31, 2023, and the related depreciation and depletion expense for the year ended December 31, 2023 was $16.6 billion. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. 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 well information such as flow rates and reservoir pressure declines, development and production costs, among 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 reserve volumes, and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil and natural gas reserve volumes. 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 reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil and natural gas reserve volumes. 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, iii) evaluating the specialists' findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, as applicable. /s/ PricewaterhouseCoopers LLP Houston, Texas February 28, 2024 We have served as the Corporation’s auditor since 1934. 77 CONSOLIDATED STATEMENT OF INCOME (millions of dollars) Revenues and other income Sales and other operating revenue Income from equity affiliates Other income Total revenues and other income Costs and other deductions Crude oil and product purchases Production and manufacturing expenses Selling, general and administrative expenses Depreciation and depletion (includes impairments) Exploration expenses, including dry holes Non-service pension and postretirement benefit expense Interest expense Other taxes and duties Total costs and other deductions Income (loss) before income taxes Income tax expense (benefit) Net income (loss) including noncontrolling interests Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to ExxonMobil Earnings (loss) per common share (dollars) Earnings (loss) per common share - assuming dilution (dollars) Note Reference Number 2023 2022 2021 18 7 2, 9 17 19 19 12 12 334,697 398,675 276,692 6,385 3,500 11,463 3,542 6,657 2,291 344,582 413,680 285,640 193,029 228,959 155,164 36,885 9,919 20,641 751 714 849 29,011 42,609 10,095 24,040 1,025 482 798 27,919 36,035 9,574 20,607 1,054 786 947 30,239 291,799 335,927 254,406 52,783 15,429 37,354 1,344 36,010 8.89 8.89 77,753 20,176 57,577 1,837 55,740 13.26 13.26 31,234 7,636 23,598 558 23,040 5.39 5.39 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 78 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (millions of dollars) 2023 2022 2021 Net income (loss) including noncontrolling interests 37,354 57,577 23,598 Other comprehensive income (loss) (net of income taxes) Foreign exchange translation adjustment Adjustment for foreign exchange translation (gain)/loss included in net income Postretirement benefits reserves adjustment (excluding amortization) Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs Total other comprehensive income (loss) Comprehensive income (loss) including noncontrolling interests Comprehensive income (loss) attributable to noncontrolling interests Comprehensive income (loss) attributable to ExxonMobil 1,241 609 (369) 61 1,542 38,896 1,605 37,291 (3,482) — 3,395 403 316 57,893 1,659 56,234 (872) (2) 3,118 925 3,169 26,767 786 25,981 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 79 CONSOLIDATED BALANCE SHEET (millions of dollars) ASSETS Current assets Cash and cash equivalents Cash and cash equivalents – restricted Notes and accounts receivable – net Inventories Crude oil, products and merchandise Materials and supplies Other current assets Total current assets Investments, advances and long-term receivables Property, plant and equipment, at cost, less accumulated depreciation and depletion Other assets, including intangibles – net Total Assets LIABILITIES Current liabilities Notes and loans payable Accounts payable and accrued liabilities Income taxes payable Total current liabilities Long-term debt Postretirement benefits reserves Deferred income tax liabilities Long-term obligations to equity companies Other long-term obligations Total Liabilities Commitments and contingencies EQUITY Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) Earnings reinvested Accumulated other comprehensive income Common stock held in treasury (4,048 million shares in 2023 and 3,937 million shares in 2022) ExxonMobil share of equity Noncontrolling interests Total Equity Total Liabilities and Equity Note Reference Number December 31, 2023 December 31, 2022 6 3 8 9 6 6 14 17 19 16 4 31,539 29,640 29 25 38,015 41,749 20,528 4,592 1,906 96,609 47,630 214,940 17,138 376,317 4,090 58,037 3,189 65,316 37,483 10,496 24,452 1,804 24,228 20,434 4,001 1,782 97,631 49,793 204,692 16,951 369,067 634 63,197 5,214 69,045 40,559 10,045 22,874 2,338 21,733 163,779 166,594 17,781 453,927 (11,989) 15,752 432,860 (13,270) (254,917) (240,293) 204,802 195,049 7,736 212,538 376,317 7,424 202,473 369,067 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 80 CONSOLIDATED STATEMENT OF CASH FLOWS (millions of dollars) Note Reference Number 2023 2022 2021 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) including noncontrolling interests Adjustments for noncash transactions Depreciation and depletion (includes impairments) Deferred income tax charges/(credits) Postretirement benefits expense in excess of/(less than) net payments Other long-term obligation provisions in excess of/(less than) payments Dividends received greater than/(less than) equity in current earnings of equity companies Changes in operational working capital, excluding cash and debt Notes and accounts receivable reduction/(increase) Inventories reduction/(increase) Other current assets reduction/(increase) Accounts and other payables increase/(reduction) Net (gain)/loss on asset sales All other items - net Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to property, plant and equipment Proceeds from asset sales and returns of investments Additional investments and advances Other investing activities including collection of advances Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES Additions to long-term debt (1) Reductions in long-term debt Additions to short-term debt Reductions in short-term debt Additions/(reductions) in debt with three months or less maturity Contingent consideration payments Cash dividends to ExxonMobil shareholders Cash dividends to noncontrolling interests Changes in noncontrolling interests Common stock acquired Net cash provided by (used in) financing activities Effects of exchange rate changes on cash Increase/(decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year 2, 9 19 5 37,354 57,577 23,598 20,641 634 90 (1,501) 509 4,370 (3,472) (426) (4,727) (513) 2,410 55,369 24,040 3,758 (2,981) (1,932) (2,446) (11,019) (6,947) (688) 18,460 (1,034) 9 76,797 20,607 303 754 50 (668) (12,098) (489) (71) 16,820 (1,207) 530 48,129 (21,919) (18,407) (12,076) 4,078 (2,995) 1,562 5,247 (3,090) 1,508 3,176 (2,817) 1,482 (19,274) (14,742) (10,235) 939 (15) — (879) (284) (68) 637 (5) 198 (8,075) 25 (58) 46 (8) 12,687 (29,396) (2,983) (30) (14,941) (14,939) (14,924) (531) (770) (17,748) (34,297) 105 1,903 29,665 31,568 (267) (1,475) (15,155) (39,114) (78) 22,863 6,802 29,665 (224) (436) (155) (35,423) (33) 2,438 4,364 6,802 (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. The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 81 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (millions of dollars) Balance as of December 31, 2020 Amortization of stock-based awards Other Net income (loss) for the year Dividends - common shares Other comprehensive income Share repurchases, at cost Dispositions Balance as of December 31, 2021 Amortization of stock-based awards Other Net income (loss) for the year Dividends - common shares Other comprehensive income Share repurchases, at cost Dispositions Balance as of December 31, 2022 Amortization of stock-based awards Other Net income (loss) for the year Dividends - common shares Other comprehensive income Share repurchases, at cost Issued for acquisitions Dispositions Balance as of December 31, 2023 Common Stock Share Activity (millions of shares) Balance as of December 31, 2020 Share repurchases, at cost Dispositions Balance as of December 31, 2021 Share repurchases, at cost Dispositions Balance as of December 31, 2022 Share repurchases, at cost Issued for acquisitions Dispositions Balance as of December 31, 2023 ExxonMobil Share of Equity Common Stock Earnings Reinvested Accumulated Other Comprehensive Income Common Stock Held in Treasury ExxonMobil Share of Equity Non- controlling Interests Total Equity 15,688 383,943 (16,705) (225,776) 157,150 6,980 164,130 534 (476) — — — — — — — 23,040 (14,924) — — — — — — — 2,941 — — — — — — — (155) 467 534 (476) 23,040 (14,924) 2,941 (155) 467 15,746 392,059 (13,764) (225,464) 168,577 481 (475) — — — — — — — 55,740 (14,939) — — — — — — — 494 — — — — — — — (15,295) 466 15,752 432,860 (13,270) (240,293) 565 (514) — — — — 1,978 — 17,781 — (2) 36,010 (14,941) — — — — 453,927 — — — — 1,281 — — — (11,989) — — — — — (17,993) 2,866 503 (254,917) 481 (475) 55,740 (14,939) 494 (15,295) 466 195,049 565 (516) 36,010 (14,941) 1,281 (17,993) 4,844 503 204,802 — 115 558 (224) 228 (551) — 7,106 — 405 1,837 (267) (178) (1,479) — 7,424 — 89 1,344 (531) 261 (851) — — 7,736 534 (361) 23,598 (15,148) 3,169 (706) 467 175,683 481 (70) 57,577 (15,206) 316 (16,774) 466 202,473 565 (427) 37,354 (15,472) 1,542 (18,844) 4,844 503 212,538 Issued Held in Treasury Outstanding 8,019 — — 8,019 — — 8,019 — — — 8,019 (3,786) (2) 8 (3,780) (165) 8 (3,937) (165) 46 8 (4,048) 4,233 (2) 8 4,239 (165) 8 4,082 (165) 46 8 3,971 The information in the Notes to Consolidated Financial Statements is an integral part of these statements. 82 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 business opportunities including carbon capture and storage, hydrogen, lower-emission fuels 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. 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. 83 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. 84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life, taking obsolescence into consideration. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Service station buildings and fixed improvements are generally depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following: • • • • • • a significant decrease in the market price of a long-lived asset; a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected reserve volumes; a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator; an accumulation of project costs significantly in excess of the amount originally expected; a current-period operating loss combined with a history and forecast of operating or cash flow losses; and a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle. Asset valuation analysis, profitability reviews, and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances can be indicators of potential impairment as well. 85 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins. In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices in the year. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves, and therefore, does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment. Global Outlook and Cash Flow Assessment. The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Global Outlook (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from unconventional operated assets in the Permian Basin. 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. 86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 2. Russia In response to Russia’s military action in Ukraine, the Corporation announced in early 2022 that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. In light of this, an impairment assessment was conducted, and management determined that the carrying value of the asset group was not recoverable. As a result, the Corporation’s first-quarter 2022 earnings included after-tax charges of $3.4 billion largely representing the full impairment of its operations related to Sakhalin. On a before-tax basis, the charges amounted to $4.6 billion, substantially all of which is reflected in the line captioned “Depreciation and depletion (including impairments)” on the Consolidated Statement of Income. Effective October 14, 2022, the Russian government unilaterally terminated the Corporation’s interests in Sakhalin, transferring operations to a Russian operator. The Corporation’s fourth-quarter 2022 results include an after-tax benefit of $1.1 billion largely reflecting the impact of the expropriation on the company’s various obligations related to Sakhalin. The Corporation's exit from the project resulted in approximately 150 million oil-equivalent barrels no longer qualifying as proved reserves at year-end 2022. 87 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. Miscellaneous Financial Information Research and development expenses totaled $879 million in 2023, $824 million in 2022, and $843 million in 2021. Net income included before-tax aggregate foreign exchange transaction losses of $51 million, $218 million, and $18 million in 2023, 2022, and 2021, respectively. LIFO Inventory. In 2023, 2022, and 2021, net income included gains of $366 million, $367 million, and $54 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by approximately $14 billion and $15 billion at December 31, 2023 and 2022, respectively. Crude oil, products, and merchandise as of year-end 2023 and 2022 consist of the following: (millions of dollars) Crude oil Petroleum products Chemical products (1) Gas/other Total Dec 31, 2023 Dec 31, 2022 6,944 6,248 3,930 3,406 20,528 6,909 6,291 3,806 3,428 20,434 (1) Chemical products includes basic chemicals (olefins and aromatics), polymers (such as polyolefins, adhesions, specialty elastomers, & butyl), intermediates (e.g. hydrocarbon fluids, plasticizers) and synthetics. Government Assistance. ASC 832 "Government Assistance" requires disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. During 2023 and 2022, certain governments outside the United States provided payments which, individually and in aggregate, were immaterial to the Corporation's financial results. Among these are programs where governments endeavor to stabilize or cap fuel and energy costs for local consumers. To compensate producers who sell at the government-mandated prices, these governments provide reimbursements to the producers. In 2023 such reimbursements were negligible and in 2022 these reimbursements totaled approximately $1.5 billion before tax, which were reflected as reductions to the line captioned "Crude oil and product purchases" on the Consolidated Statement of Income. At December 31, 2022, "Notes and accounts receivable - net" on the Consolidated Balance Sheet included $0.5 billion related to pending government reimbursements. The terms and conditions of these programs, including their duration, vary by country. In the event that any of these programs are discontinued, the Corporation does not expect a significant impact to its financial results. Additionally, in connection with cap and trade programs in certain countries outside the United States, companies receive allowances from governments covering a specified level of emissions from facilities they operate. The terms of these programs vary by country. The Corporation records these allowances at a nominal amount, generally in "Inventories - Crude oil, products and merchandise" on the Consolidated Balance Sheet. 88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. Other Comprehensive Income Information ExxonMobil Share of Accumulated Other Comprehensive Income (millions of dollars) Cumulative Foreign Exchange Translation Adjustment Postretirement Benefits Reserves Adjustment Total Balance as of December 31, 2020 Current period change excluding amounts reclassified from accumulated other comprehensive income Amounts reclassified from accumulated other comprehensive income Total change in accumulated other comprehensive income Balance as of December 31, 2021 Current period change excluding amounts reclassified from accumulated other comprehensive income (1) Amounts reclassified from accumulated other comprehensive income Total change in accumulated other comprehensive income Balance as of December 31, 2022 Current period change excluding amounts reclassified from accumulated other comprehensive income (1) Amounts reclassified from accumulated other comprehensive income Total change in accumulated other comprehensive income Balance as of December 31, 2023 (10,614) (883) (2) (885) (11,499) (3,092) — (3,092) (14,591) 1,108 427 1,535 (13,056) (6,091) 2,938 888 3,826 (2,265) 3,205 381 3,586 1,321 (305) 51 (254) 1,067 (16,705) 2,055 886 2,941 (13,764) 113 381 494 (13,270) 803 478 1,281 (11,989) (1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) net of taxes of $(135) million and $230 million in 2023 and 2022, respectively. Amounts Reclassified Out of Accumulated Other Comprehensive Income - Before-tax Income/(Expense) (millions of dollars) 2023 2022 2021 Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense) (609) — 2 (81) (519) (1,229) Income Tax (Expense)/Credit For Components of Other Comprehensive Income (millions of dollars) Foreign exchange translation adjustment Postretirement benefits reserves adjustment (excluding amortization) Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs Total 2023 2022 2021 341 200 (20) 521 54 (1,120) (116) (1,182) (114) (983) (304) (1,401) 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Cash Flow Information The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents. In 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 21. In 2023, the Corporation completed the sale of Esso Thailand. The sale included cash proceeds as well as cash from debt that was issued to facilitate the sale, which was assumed by the buyer upon closing. For 2023, 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. For 2022, the number includes before-tax amounts from the sale of certain unproved assets in Romania and unconventional assets in Canada and the United States, as well as other smaller divestments. For 2021, the number includes before-tax amounts from the sale of non-operated upstream assets in the United Kingdom Central and Northern North Sea and the sale of ExxonMobil's global Santoprene business. These net (gain)/loss amounts are reported in "Other income" on the Consolidated Statement of Income. (millions of dollars) Income taxes paid Cash interest paid Included in cash flows from operating activities Capitalized, included in cash flows from investing activities Total cash interest paid 2023 2022 2021 15,473 15,364 5,341 584 1,152 1,736 666 838 1,504 819 655 1,474 6. Additional Working Capital Information (millions of dollars) Dec 31, 2023 Dec 31, 2022 Notes and accounts receivable Trade, less reserves of $170 million and $168 million Other, less reserves of $101 million and $402 million Total Notes and loans payable Bank loans Commercial paper Long-term debt due within one year Total Accounts payable and accrued liabilities Trade payables Payables to equity companies Accrued taxes other than income taxes Other Total 30,296 7,719 38,015 6 75 4,009 4,090 31,249 11,885 3,817 11,086 58,037 32,844 8,905 41,749 379 74 181 634 33,169 14,585 3,969 11,474 63,197 Trade notes and accounts receivables include both receivables within the scope of ASC 606 and outside the scope of ASC 606. Receivables outside the scope of ASC 606 primarily relate to physically settled commodity contracts accounted for as derivatives. Credit quality and type of customer are generally similar between receivables within the scope of ASC 606 and those outside it. The Corporation has short-term committed lines of credit of $0.3 billion which were unused as of December 31, 2023. These lines are available for general corporate purposes. 90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. Equity Company Information The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, natural gas marketing, transportation of crude oil, and petrochemical manufacturing in North America; natural gas production and distribution in Europe; LNG operations in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining and marketing ventures. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 9 percent, 11 percent, and 10 percent in the years 2023, 2022, and 2021, 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. Impairments related to Upstream equity investments of $0.6 billion, $0.6 billion, and $0.2 billion in 2023, 2022, and 2021, respectively, are included in “Income from equity affiliates” or “Other income” on the Consolidated Statement of Income. Equity Company Financial Summary (millions of dollars) Total revenues Income before income taxes Income taxes Income from equity affiliates Current assets Long-term assets Total assets Current liabilities Long-term liabilities Net assets 2023 2022 2021 Total ExxonMobil Share Total ExxonMobil Share Total ExxonMobil Share 183,812 61,550 23,149 38,401 77,457 153,186 230,643 53,640 62,009 114,994 57,528 19,279 7,603 11,676 24,994 42,921 67,915 15,555 18,929 33,431 116,972 34,995 35,142 11,010 24,132 45,267 150,699 195,966 28,862 63,138 103,966 9,278 2,763 6,515 15,542 41,614 57,156 8,297 19,084 29,775 132,783 35,999 11,404 24,595 53,081 150,198 203,279 30,721 57,237 115,321 40,682 10,078 3,085 6,993 18,713 40,986 59,699 9,652 17,059 32,988 91 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A list of significant equity companies as of December 31, 2023, together with the Corporation’s percentage ownership interest, is detailed below: Percentage Ownership Interest 7 50 8 25 50 25 30 30 10 36 50 33 17 24 25 25 31 30 24 25 71 50 45 25 50 50 12 50 50 Upstream Barzan Gas Company Limited BEB Erdgas und Erdoel GmbH & Co. KG Caspian Pipeline Consortium Coral FLNG S.A. Cross Timbers Energy LLC GasTerra B.V. Golden Pass LNG Terminal LLC Golden Pass Pipeline LLC Marine Well Containment Company LLC Mozambique Rovuma Venture S.p.A. Nederlandse Aardolie Maatschappij B.V. Papua New Guinea Liquefied Natural Gas Global Company LDC Permian Highway Pipeline LLC QatarEnergy LNG N (2) QatarEnergy LNG NFE (3) QatarEnergy LNG S (1) QatarEnergy LNG S (2) QatarEnergy LNG S (3) South Hook LNG Terminal Company Limited Tengizchevroil LLP Terminale GNL Adriatico S.r.l. Energy Products, Chemical Products, and/or Specialty Products Al-Jubail Petrochemical Company Alberta Products Pipe Line Ltd. Fujian Refining & Petrochemical Co. Ltd. Gulf Coast Growth Ventures LLC Infineum USA L.P. Permian Express Partners LLC Saudi Aramco Mobil Refinery Company Ltd. Saudi Yanbu Petrochemical Co. 92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. Investments, Advances and Long-Term Receivables (millions of dollars) Dec 31, 2023 Dec 31, 2022 Equity method company investments and advances Investments Advances, net of allowances of $33 million and $28 million Total equity method company investments and advances Equity securities carried at fair value and other investments at adjusted cost basis Long-term receivables and miscellaneous, net of reserves of $1,966 million and $1,623 million Total 34,080 7,527 41,607 177 5,846 47,630 34,522 8,049 42,571 278 6,944 49,793 9. Property, Plant and Equipment and Asset Retirement Obligations Property, Plant and Equipment (millions of dollars) December 31, 2023 December 31, 2022 Cost Net Cost Net Upstream Energy Products Chemical Products Specialty Products Other Total 359,031 148,245 350,748 144,146 57,400 38,801 9,385 22,768 487,385 27,284 20,329 4,378 14,704 214,940 58,393 36,322 8,895 18,335 472,693 26,765 19,064 4,303 10,414 204,692 In 2023, the Corporation identified situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable and conducted impairment assessments. Before-tax charges of $3.3 billion were recognized, in large part due to impairing the idled Upstream Santa Ynez Unit assets and associated facilities in California, reflecting the continuing challenges in the state regulatory environment that impeded progress in restoring operations. Other before-tax impairment charges recognized during 2023 included $0.3 billion in Upstream, $0.3 billion in Chemical Products, and $0.1 billion in Specialty Products. In 2022, before-tax impairment charges of $4.5 billion were recognized during the first quarter as a result of the Corporation's plans to discontinue operations on the Sakhalin-1 project and develop steps to exit the venture in response to Russia's military action in Ukraine (Refer to Note 2 for additional information). Other before-tax impairment charges recognized during 2022 included $1.5 billion in Upstream and $0.4 billion in Energy Products. In 2021, the Corporation recognized before-tax impairment charges of $1.2 billion largely as a result of changes to Upstream development plans. 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 $272,445 million at the end of 2023 and $268,001 million at the end of 2022. 93 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Asset Retirement Obligations The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for facilities in the Product Solutions business generally become firm at the time a decision is made to permanently shut down and dismantle the facilities. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites generally have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. The following table summarizes the activity in the liability for asset retirement obligations: (millions of dollars) 2023 2022 2021 Balance at January 1 Accretion expense and other provisions Reduction due to property sales Payments made Liabilities incurred Foreign currency translation Revisions Balance at December 31 10,491 10,630 734 (288) (693) 831 124 1,790 12,989 744 (328) (518) 119 (330) 174 11,247 548 (1,002) (444) 42 (147) 386 10,491 10,630 The long-term Asset Retirement Obligations were $11,942 million and $9,650 million at December 31, 2023 and 2022, respectively, and are included in “Other long-term obligations” on the Consolidated Balance Sheet. Estimated cash payments in 2024 and 2025 are $1,047 million and $899 million, respectively. 94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. Accounting for Suspended Exploratory Well Costs The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. The following two tables provide details of the changes in the balance of suspended exploratory well costs, including an aging summary of those costs. Change in capitalized suspended exploratory well costs (millions of dollars) Balance beginning at January 1 Additions pending the determination of proved reserves Charged to expense Reclassifications to wells, facilities and equipment based on the determination of proved reserves Divestments/Other Ending balance at December 31 Ending balance attributed to equity companies included above Period-end capitalized suspended exploratory well costs (millions of dollars) Capitalized for a period of one year or less Capitalized for a period of between one and five years Capitalized for a period of between five and ten years Capitalized for a period of greater than ten years Capitalized for a period greater than one year - subtotal Total 2023 2022 2021 3,512 4,120 4,382 200 (95) (142) 84 3,559 306 378 (259) (142) (585) 3,512 306 420 (325) (328) (29) 4,120 306 2023 2022 2021 200 1,030 1,411 918 3,359 3,559 378 969 1,410 755 3,134 3,512 420 1,642 1,657 401 3,700 4,120 Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with only exploratory well costs capitalized for a period of one year or less and those that have had exploratory well costs capitalized for a period greater than one year. Number of projects that only have exploratory well costs capitalized for a period of one year or less Number of projects that have exploratory well costs capitalized for a period greater than one year Total 2023 2022 2021 — 31 31 10 26 36 4 30 34 Of the 31 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2023, 16 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 progressing toward development. 95 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The table below provides additional detail for those 15 projects, which total $2,389 million. Country/Project Angola Block 32 Central NE Hub Argentina La Invernada Australia December 31, 2023 (millions of dollars) Years Wells Drilled / Acquired Comment 66 72 2007 - 2021 Evaluating development plan to tie into existing infrastructure. 2014 Evaluating development plan to tie into planned infrastructure. Gorgon Area Ullage 308 1994 - 2015 Evaluating development plans to tie into existing LNG facilities. Canada Hibernia North Guyana Whiptail Kazakhstan Kairan 25 2019 Awaiting capacity in existing/planned infrastructure. 178 2019 - 2022 Continuing discussions with the government regarding development plan. 53 2004 - 2007 Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan. Mozambique Rovuma LNG Phase 1 Rovuma LNG Future Non- Straddling Train Rovuma LNG Unitized Trains 150 120 35 2017 2017 2017 Progressing development plan to tie into planned LNG facilities. Evaluating/progressing development plan to tie into planned LNG facilities. Evaluating/progressing development plan to tie into planned LNG facilities. Nigeria Bonga North Papua New Guinea Papua LNG Muruk P'nyang Tanzania Block 2 Vietnam Blue Whale Total 2023 (15 projects) 34 2004 - 2009 Progressing development plan to tie into existing/planned infrastructure. 246 165 116 525 296 2,389 2017 Evaluating/progressing development plans. 2017 - 2019 Evaluating/progressing development plans. 2012 - 2018 Evaluating/progressing development plans. 2012 - 2015 Evaluating development alternatives, while continuing discussions with the government regarding development plan. 2011 - 2015 Evaluating/progressing development plans. 96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. Leases The Corporation and its consolidated affiliates generally purchase the property, plant and equipment used in operations, but there are situations where assets are leased, primarily for drilling equipment, tankers, office buildings, railcars, and other moveable equipment. Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for drilling equipment, tankers, and finance leases is excluded from the calculation of right of use assets and lease liabilities. Generally, assets are leased only for a portion of their useful lives and are accounted for as operating leases. In limited situations, assets are leased for nearly all of their useful lives and are accounted for as finance leases. Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. In general, leases are capitalized using the incremental borrowing rate of the leasing affiliate. The Corporation’s activities as a lessor are not significant. Lease Cost (millions of dollars) Operating lease cost Short-term and other (net of sublease rental income) Amortization of right of use assets Interest on lease liabilities Total (1) Operating Leases Finance Leases 2023 2022 2021 2023 2022 2021 1,976 1,563 1,776 1,389 1,542 1,351 3,539 3,165 2,893 107 140 247 243 210 453 133 158 291 (1) Includes $999 million, $908 million, and $681 million for drilling rigs and related equipment operating leases in 2023, 2022, and 2021, respectively. Balance Sheet (millions of dollars) Right of use assets Operating Leases Finance Leases December 31, 2023 December 31, 2022 December 31, 2023 December 31, 2022 Included in Other assets, including intangibles - net Included in Property, plant and equipment - net Total right of use assets Lease liability due within one year 6,849 6,849 6,451 6,451 Included in Accounts payable and accrued liabilities 1,617 1,527 Included in Notes and loans payable Long-term lease liability Included in Other long-term obligations 4,393 4,067 Included in Long-term debt Included in Long-term obligations to equity companies Total lease liability (2) Weighted-average remaining lease term (years) Weighted-average discount rate (percent) 6,010 5,594 8 3.9 % 9 2.4 % 2,712 2,712 5 95 1,821 121 2,042 26 7.2 % 2,090 2,090 5 69 1,389 126 1,589 22 8.0 % (2) Includes $2,032 million and $1,646 million for drilling rigs and related equipment operating leases in 2023 and 2022, respectively. 97 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Maturity Analysis of Lease Liabilities (millions of dollars) Operating Leases Finance Leases December 31, 2023 2024 2025 2026 2027 2028 2029 and beyond Total lease payments Discount to present value Total lease liability 1,807 1,464 1,046 577 307 1,781 6,982 (972) 6,010 243 237 234 224 241 2,256 3,435 (1,393) 2,042 In addition to the lease liabilities in the table immediately above, at December 31, 2023, undiscounted commitments for leases not yet commenced totaled $4,063 million for operating leases and $2,256 million for finance leases. Estimated cash payments for operating and finance leases not yet commenced are $267 million and $331 million for 2024 and 2025 respectively. Not yet commenced finance leases primarily relate to a CO2 transportation and service agreement, and a long-term hydrogen purchase agreement. The underlying assets are primarily designed by, and are being constructed by, the lessors. Other Information (millions of dollars) Cash paid for amounts included in the measurement of lease liabilities Cash flows from operating activities Cash flows from investing activities Cash flows from financing activities Noncash right of use assets recorded for lease liabilities In exchange for lease liabilities during the period Operating Leases Finance Leases 2023 2022 2021 2023 2022 2021 1,135 758 1,119 500 1,135 291 20 86 20 20 149 110 2,161 1,997 1,405 529 73 200 98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. Earnings Per Share Earnings per common share Net income (loss) attributable to ExxonMobil (millions of dollars) Weighted-average number of common shares outstanding (millions of shares) (1) Earnings (loss) per common share (dollars) (2) Dividends paid per common share (dollars) 2023 2022 2021 36,010 55,740 23,040 4,052 8.89 3.68 4,205 13.26 3.55 4,275 5.39 3.49 (1) (2) Includes restricted shares not vested. The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown. 99 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. Financial Instruments and Derivatives The estimated fair value of financial instruments and derivatives at December 31, 2023, and December 31, 2022, and the related hierarchy level for the fair value measurement was as follows: (millions of dollars) Assets (1) Derivative assets Advances to/receivables from equity companies Other long-term financial assets (2)(6) (3) Fair Value Level 1 Level 2 Level 3 4,544 1,731 — — 2,517 1,389 — (4) Liabilities Derivative liabilities Long-term debt Long-term obligations to equity companies Other long-term financial liabilities (5) (6) 4,056 30,556 — — 1,608 2,004 — — (7) December 31, 2023 Total Gross Assets & Liabilities Effect of Counterparty Netting Effect of Collateral Netting Difference in Carrying Value and Fair Value Net Carrying Value 6,275 7,008 2,333 5,664 32,560 1,896 697 (5,177) (528) — — (5,177) — — — — — (40) — — — — 519 202 — 3,102 (92) 45 570 7,527 2,535 447 35,662 1,804 742 December 31, 2022 4,491 944 — — 1,896 697 (millions of dollars) Assets (1) Derivative assets Advances to/receivables from equity companies (2)(6) Other long-term financial assets (3) (4) Liabilities Derivative liabilities Long-term debt Long-term obligations to equity companies Other long-term financial liabilities (5) (6) (7) Fair Value Level 1 Level 2 Level 3 4,309 3,455 — — 1,208 3,417 33,112 — — 2,406 — 3,264 1,880 — — 4,958 1,413 — 6 2,467 679 Total Gross Assets & Liabilities Effect of Counterparty Netting Effect of Collateral Netting Difference in Carrying Value and Fair Value Net Carrying Value 7,764 7,364 2,621 6,681 34,998 2,467 679 (5,778) (969) — — (5,778) — — — — — (79) — — — — 685 346 1,017 8,049 2,967 — 824 4,173 39,171 (129) 38 2,338 717 (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) (4) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles - net. 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 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, 2023, and December 31, 2022, respectively, the Corporation had $800 million and $1,494 million of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements. 100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. Commodity contracts held for trading purposes are presented in the Consolidated Statement of Income on a net basis in the line “Sales and other operating revenue” and in the Consolidated Statement of Cash Flows in “Cash Flows from Operating Activities”. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2023 and 2022, or results of operations for 2023, 2022, and 2021. 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, 2023, and December 31, 2022, was as follows: (millions) Crude oil (barrels) Petroleum products (barrels) Natural gas (MMBTUs) December 31, December 31, 2023 2022 (7) (43) (560) 4 (52) (64) Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are included in the following lines on a before- tax basis: (millions of dollars) Sales and other operating revenue Crude oil and product purchases Total 2023 2022 2021 986 79 1,065 (1,763) 314 (1,449) (3,818) 48 (3,770) 14. Long-Term Debt At December 31, 2023, long-term debt consisted of $32,510 million due in U.S. dollars and $4,973 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $4,009 million, which matures within one year and is included in current liabilities. On December 22, 2022, the Company irrevocably deposited sufficient cash with the Trustee to fund (i) the redemption of its 2.726% notes due 2023 and (ii) the redemption of its 1.571% notes due 2023. After the deposit of the funds, the Corporation was released from its obligation and the debt was extinguished. The amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2024, in millions of dollars, are: 2025 – $5,371; 2026 – $3,651; 2027 – $1,098; and 2028 – $1,207. At December 31, 2023, the Corporation's unused long-term lines of credit were $1.3 billion. The Corporation may use non-derivative financial instruments, such as its foreign currency-denominated debt, as hedges of its net investments in certain foreign subsidiaries. Under this method, the change in the carrying value of the financial instruments due to foreign exchange fluctuations is reported in accumulated other comprehensive income. As of December 31, 2023, the Corporation has designated its $5.0 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. 101 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Summarized long-term debt at year-end 2023 and 2022 are shown in the table below: (millions of dollars, except where stated otherwise) Average (1) Rate Dec 31, 2023 Dec 31, 2022 Exxon Mobil Corporation (2) 3.176% notes due 2024 2.019% notes due 2024 2.709% notes due 2025 2.992% notes due 2025 3.043% notes due 2026 2.275% notes due 2026 3.294% notes due 2027 2.440% notes due 2029 3.482% notes due 2030 2.610% notes due 2030 2.995% notes due 2039 4.227% notes due 2040 3.567% notes due 2045 4.114% notes due 2046 3.095% notes due 2049 4.327% notes due 2050 3.452% notes due 2051 Exxon Mobil Corporation - Euro-denominated 0.142% notes due 2024 0.524% notes due 2028 0.835% notes due 2032 1.408% notes due 2039 XTO Energy Inc. (3) 6.100% senior notes due 2036 6.750% senior notes due 2037 6.375% senior notes due 2038 — — 1,750 2,767 2,500 1,000 1,000 1,250 2,000 2,000 750 2,080 1,000 2,500 1,500 2,750 2,750 — 1,105 1,105 1,105 189 286 223 1,000 1,000 1,750 2,781 2,500 1,000 1,000 1,250 2,000 2,000 750 2,084 1,000 2,500 1,500 2,750 2,750 1,600 1,066 1,066 1,066 189 289 224 Industrial revenue bonds due 2022-2051 Finance leases & other obligations Debt issuance costs Total long-term debt 3.080% 5.985% 2,123 3,838 (88) 37,483 2,245 3,299 (100) 40,559 (1) Average effective or imputed interest rates at December 31, 2023. (2) Includes premiums of $97 million in 2023 and $115 million in 2022. (3) Includes premiums of $71 million in 2023 and $76 million in 2022. 102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 15. Incentive Program The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock, and other forms of awards. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. 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 Board terminates the plan early. At the end of 2023, remaining shares available for award under the 2003 Incentive Program were 54 million. Restricted Stock and Restricted Stock Units. Awards totaling 9,701 thousand, 9,392 thousand, and 8,133 thousand of restricted (nonvested) common stock units were granted in 2023, 2022, and 2021, 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. The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2023. Restricted stock and units outstanding Issued and outstanding at January 1 Awards issued in 2023 Vested Forfeited Issued and outstanding at December 31 Value of restricted stock units Grant price (dollars) Value at date of grant: Units settled in stock Units settled in cash Total value 2023 Shares Weighted-Average Grant-Date Fair Value per Share (thousands) (dollars) 37,573 9,247 (8,572) (436) 37,812 67.47 110.84 67.75 73.62 77.94 2023 2022 103.16 110.46 2021 62.76 (millions of dollars) 900 101 1,001 931 106 1,037 461 49 510 As of December 31, 2023, there was $2,120 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.7 years. The compensation cost charged against income for the restricted stock and restricted stock units was $611 million, $648 million, and $612 million for 2023, 2022, and 2021, respectively. The income tax benefit recognized in income related to this compensation expense was $50 million, $52 million, and $49 million for the same periods, respectively. The fair value of shares and units vested in 2023, 2022, and 2021 was $892 million, $1,027 million, and $562 million, respectively. Cash payments of $79 million, $89 million, and $48 million for vested restricted stock units settled in cash were made in 2023, 2022, and 2021, respectively. 103 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. Litigation and Other Contingencies Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. State and local governments and other entities in various jurisdictions across the United States and its territories have filed a number of legal proceedings against several oil and gas companies, including ExxonMobil, requesting unprecedented legal and equitable relief for various alleged injuries purportedly connected to climate change. These lawsuits assert a variety of novel, untested claims under statutory and common law. Additional such lawsuits may be filed. We believe the legal and factual theories set forth in these proceedings are meritless and represent an inappropriate attempt to use the court system to usurp the proper role of policymakers in addressing the societal challenges of climate change. Local governments in Louisiana have filed unprecedented legal proceedings against a number of oil and gas companies, including ExxonMobil, requesting compensation for the restoration of coastal marsh erosion in the state. We believe the factual and legal theories set forth in these proceedings are meritless. While the outcome of any litigation can be unpredictable, we believe the likelihood is remote that the ultimate outcomes of these lawsuits will have a material adverse effect on the Corporation’s operations, financial condition, or financial statements taken as a whole. We will continue to defend vigorously against these claims. Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2023, 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. (millions of dollars) Guarantees Debt-related Other Total (1) ExxonMobil share. December 31, 2023 Equity Company Obligations (1) Other Third-Party Obligations Total 1,151 711 1,862 149 5,796 5,945 1,300 6,507 7,807 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. 104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. Pension and Other Postretirement Benefits The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31. (millions of dollars, except where stated otherwise) U.S. Non-U.S. 2023 2022 2023 2022 2023 2022 Pension Benefits Other Postretirement Benefits Weighted-average assumptions used to determine benefit obligations at December 31 Discount rate (percent) Long-term rate of compensation increase (percent) Change in benefit obligation Benefit obligation at January 1 Service cost Interest cost Actuarial loss/(gain) (1) Benefits paid Foreign exchange rate changes (2)(3) Amendments, divestments and other Benefit obligation at December 31 Accumulated benefit obligation at December 31 (1) Actuarial loss/(gain) primarily reflects lower discount rates. (2) Benefit payments for funded and unfunded plans. 5.30 4.50 5.60 4.50 4.30 4.50 4.90 5.20 5.30 4.50 5.60 4.50 12,350 18,511 19,342 29,492 5,211 7,265 466 664 550 (870) — (17) 13,143 11,033 712 518 (4,432) (2,959) — — 12,350 10,367 323 922 1,393 (1,214) 515 46 21,327 19,769 570 614 (7,742) (1,415) (2,258) 81 19,342 18,047 78 276 176 (545) 11 (193) 5,014 — 138 216 (1,990) (492) (47) 121 5,211 — (3) For 2023 and 2022, other postretirement benefits paid are net of $19 million and $24 million of Medicare subsidy receipts, respectively. For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.0 percent in 2025 and subsequent years. (millions of dollars) Change in plan assets Fair value at January 1 Actual return on plan assets Foreign exchange rate changes Company contribution Benefits paid Other (1) Fair value at December 31 (1) Benefit payments for funded plans. Pension Benefits Other Postretirement Benefits U.S. Non-U.S. 2023 2022 2023 2022 2023 2022 13,266 (3,265) — 3,596 (2,608) — 10,989 16,757 1,484 492 615 (878) (39) 18,431 24,880 (5,287) (2,012) 655 (1,070) (409) 16,757 348 36 — 38 (51) — 371 440 (66) — 27 (53) — 348 10,989 1,121 — — (743) — 11,367 105 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local applicable tax rules and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate. (millions of dollars) Assets in excess of/(less than) benefit obligation Balance at December 31 Funded plans Unfunded plans Total Pension Benefits U.S. Non-U.S. 2023 2022 2023 2022 (271) (1,505) (1,776) (23) (1,338) (1,361) 1,028 (3,924) (2,896) 1,019 (3,604) (2,585) 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 statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income. (millions of dollars) Assets in excess of/(less than) benefit obligation Pension Benefits Other Postretirement Benefits U.S. Non-U.S. 2023 2022 2023 2022 2023 2022 Balance at December 31 (1) (1,776) (1,361) (2,896) (2,585) (4,643) (4,863) Amounts recorded in the consolidated balance sheet consist of: Other assets Current liabilities Postretirement benefits reserves Total recorded Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss/(gain) Prior service cost Total recorded in accumulated other comprehensive income (1) Fair value of assets less benefit obligation shown on the preceding page. — (201) (1,575) (1,776) — (168) (1,193) (1,361) 1,895 (225) (4,566) (2,896) 1,962 (254) (4,293) (2,585) — (288) (4,355) (4,643) — (304) (4,559) (4,863) 897 (295) 1,364 401 846 278 (1,453) (459) (1,726) (190) 602 1,765 1,124 (1,912) (1,916) 744 (283) 461 106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. (millions of dollars, except where stated otherwise) Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 Discount rate (percent) Long-term rate of return on funded assets (percent) Long-term rate of compensation increase (percent) Components of net periodic benefit cost Pension Benefits Other Postretirement Benefits U.S. Non-U.S. 2023 2022 2021 2023 2022 2021 2023 2022 2021 5.60 3.00 2.80 4.90 2.20 1.60 5.60 3.10 2.80 5.20 4.60 5.30 4.20 3.50 4.10 4.70 3.80 4.60 4.50 4.50 5.50 5.20 4.20 4.20 4.50 4.50 5.50 Service cost Interest cost 466 664 712 518 919 558 323 922 570 614 774 526 Expected return on plan assets (532) (560) (722) (688) (815) (1,031) Amortization of actuarial loss/(gain) Amortization of prior service cost Net pension enhancement and curtailment/settlement cost Net periodic benefit cost 85 (29) 156 (29) 29 205 244 (23) 489 683 1,002 1,465 108 52 5 722 180 43 4 596 420 57 32 778 Changes in amounts recorded in accumulated other comprehensive income: Net actuarial loss/(gain) Amortization of actuarial (loss)/gain Prior service cost/(credit) Amortization of prior service (cost)/credit Foreign exchange rate changes Total recorded in other comprehensive income Total recorded in net periodic benefit cost and other comprehensive income, before tax (39) (114) (17) 29 — (607) (361) — 29 — (504) (733) (72) 23 — 602 (1,641) (2,361) (108) (183) (430) 153 (52) 46 84 (40) 92 (55) (199) (255) (141) (939) (1,286) 641 (1,979) (3,009) 4 (1,881) (925) 542 63 179 1,363 (1,383) (2,231) 180 (1,577) (501) 78 276 (14) (122) (42) — 176 154 122 (312) 42 (2) 138 216 (14) 6 (42) — 304 188 221 (19) 76 (42) — 424 (1,910) (891) (6) — 42 (7) (76) — 42 — Costs for defined contribution plans were $383 million, $365 million, and $177 million in 2023, 2022, and 2021, respectively. 107 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the change in accumulated other comprehensive income is shown in the table below: (millions of dollars) (Charge)/credit to other comprehensive income, before tax U.S. pension Non-U.S. pension Other postretirement benefits Total (charge)/credit to other comprehensive income, before tax (Charge)/credit to income tax (see Note 4) (Charge)/credit to investment in equity companies (Charge)/credit to other comprehensive income including noncontrolling interests, after tax Charge/(credit) to equity of noncontrolling interests (Charge)/credit to other comprehensive income attributable to ExxonMobil Total Pension and Other Postretirement Benefits 2023 2022 2021 141 (641) (4) (504) 180 16 (308) 54 (254) 939 1,979 1,881 4,799 (1,236) 235 3,798 (212) 3,586 1,286 3,009 925 5,220 (1,287) 110 4,043 (217) 3,826 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 10 to 35 percent in equity securities and the remainder in fixed income securities. The equity for the U.S. and certain non- U.S. plans include allocations to private equity partnerships that primarily focus on early-stage venture capital of less than 5 percent. 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. 108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2023 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below: U.S. Pension Fair Value Measurement at December 31, 2023, Using: Level 1 Level 2 Level 3 — — — — — — — — — — — — — 4,699 (2) 2,650 (2) — — — — 7,349 — — — — — — — — — — (millions of dollars) Asset category: Equity securities U.S. Non-U.S. Private equity Debt securities Corporate Government Asset-backed Other Real Estate Cash Total at fair value Insurance contracts at contract value Total plan assets Net Asset Value 2,114 1,344 375 1 2 1 — — 178 Non-U.S. Pension Fair Value Measurement at December 31, 2023, Using: Total Level 1 Level 2 Level 3 Net Asset Value Total 2,114 1,344 375 4,700 2,652 1 — — 178 — 52 (1) — — 134 (3) — — — 189 375 — — — 61 (2) 171 (2) 22 (2) — — 17 (4) 271 — — — — — — — — — — 2,642 1,688 294 4,370 8,429 221 4 70 45 2,642 1,740 294 4,431 8,734 243 4 70 251 17,763 18,409 22 18,431 4,015 11,364 3 11,367 (1) (2) (3) (4) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. (millions of dollars) Asset category: Equity securities U.S. Non-U.S. Debt securities Corporate Government Asset-backed Cash Total at fair value Other Postretirement Fair Value Measurement at December 31, 2023, Using: Level 1 Level 2 Level 3 Net Asset Value Total 84 (1) 40 (1) — — — — 124 — — 61 (2) 182 (2) 3 (2) 1 247 — — — — — — — — — — — — — — 84 40 61 182 3 1 371 (1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. 109 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2022 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below: U.S. Pension Fair Value Measurement at December 31, 2022, Using: Level 1 Level 2 Level 3 — — — — — — — — — — — 4,582 (2) 2,869 (2) — — 7,451 — — — — — — — — (millions of dollars) Asset category: Equity securities U.S. Non-U.S. Private equity Debt securities Corporate Government Asset-backed Cash Total at fair value Insurance contracts at contract value Total plan assets Net Asset Value 1,726 1,131 506 1 2 1 168 Non-U.S. Pension Fair Value Measurement at December 31, 2022, Using: Total Level 1 Level 2 Level 3 Net Asset Value Total 1,726 1,131 506 4,583 2,871 1 168 — 61 (1) — — 202 (3) — 88 3,535 10,986 351 3 10,989 — — — 63 (2) 144 (2) 22 (2) 40 (4) 269 — — — — — — — — 2,318 1,676 472 4,199 7,189 185 77 2,318 1,737 472 4,262 7,535 207 205 16,116 16,736 21 16,757 (1) (2) (3) (4) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. (millions of dollars) Asset category: Equity securities U.S. Non-U.S. Debt securities Corporate Government Asset-backed Cash Total at fair value Other Postretirement Fair Value Measurement at December 31, 2022, Using: Level 1 Level 2 Level 3 Net Asset Value Total 70 (1) 37 (1) — — — — 107 — — 59 (2) 175 (2) 4 (2) 3 241 — — — — — — — — — — — — — — 70 37 59 175 4 3 348 (1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. 110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of pension plans with an accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below: (millions of dollars) For funded pension plans with an accumulated benefit obligation in excess of plan assets: Accumulated benefit obligation Fair value of plan assets For funded pension plans with a projected benefit obligation in excess of plan assets: Projected benefit obligation Fair value of plan assets For unfunded pension plans: Projected benefit obligation Accumulated benefit obligation Pension Benefits U.S. Non-U.S. 2023 2022 2023 2022 — — 11,638 11,367 1,505 1,173 — — 11,012 10,989 1,338 1,045 1,145 562 2,334 1,465 3,924 3,592 1,098 400 1,956 1,012 3,604 3,261 All other postretirement benefit plans are unfunded or underfunded. (millions of dollars) U.S. Non-U.S. Gross Medicare Subsidy Receipt Pension Benefits Other Postretirement Benefits Contributions expected in 2024 Benefit payments expected in: 2024 2025 2026 2027 2028 2029 - 2033 — 275 1,053 1,053 1,064 1,066 1,087 5,644 1,200 1,158 1,144 1,185 1,216 6,116 — 363 356 347 342 339 1,710 — — — 1 1 1 3 18. Disclosures about Segments and Related Information Our reportable segments are Upstream, Energy Products, Chemical Products, and Specialty Products. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Energy Products, Chemical Products, and Specialty Products segments are organized and operate 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 Earnings after income tax include 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 $234 million in 2023, $117 million in 2022, and $103 million in 2021. 111 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (millions of dollars) Upstream Energy Products U.S. Non-U.S. U.S. Non-U.S. Chemical Products U.S. Non-U.S. Specialty Products U.S. Non-U.S. Corporate and Financing Corporate Total As of December 31, 2023 Earnings (loss) after income tax Earnings of equity companies included above Sales and other operating revenue Intersegment revenue Depreciation and depletion expense Interest revenue Interest expense Income tax expense (benefit) Additions to property, plant and equipment Investments in equity companies Total assets As of December 31, 2022 Earnings (loss) after income tax Earnings of equity companies included above Sales and other operating revenue Intersegment revenue Depreciation and depletion expense Interest revenue Interest expense Income tax expense (benefit) Additions to property, plant and equipment Investments in equity companies Total assets As of December 31, 2021 Earnings (loss) after income tax Earnings of equity companies included above Sales and other operating revenue Intersegment revenue Depreciation and depletion expense Interest revenue Interest expense Income tax expense (benefit) Additions to property, plant and equipment Investments in equity companies Total assets 4,202 17,106 6,123 6,019 63 9,500 20,971 8,863 — 82 1,016 10,372 4,436 67,452 5,550 16,074 38,982 7,737 — 74 10,593 8,217 21,485 138,914 140 103,868 23,481 765 — 4 1,543 1,106 406 32,123 131 164,515 28,258 797 — 7 1,492 1,455 1,135 42,337 1,626 126 7,951 7,991 605 — 2 396 600 3,086 17,599 11 761 14,314 3,643 706 — 2 158 1,775 2,700 17,076 11,728 24,751 8,340 6,626 2,328 1,215 411 14,579 25,658 5,791 — 51 3,330 5,940 4,893 66,695 10,133 30,585 46,076 14,013 — 38 11,575 6,441 21,502 139,764 126 117,824 29,001 741 — 1 2,615 1,141 368 31,729 322 188,153 36,894 1,246 — 7 2,420 964 1,154 41,836 91 10,670 9,081 542 — — 520 1,026 3,124 17,342 771 16,949 5,201 446 — 1 292 1,692 2,417 15,875 3,663 12,112 668 (1,014) 3,697 3,292 288 8,883 16,692 6,831 — 58 1,116 3,308 4,999 67,294 5,535 12,914 33,405 9,918 — 36 4,871 5,308 18,544 141,978 122 78,500 16,735 700 — 1 156 979 353 26,932 (139) 11,995 5,993 505 — — 1,235 538 3,019 16,695 1,141 16,633 4,082 450 — 1 684 712 2,490 14,555 100 130,406 25,097 1,036 — 6 (165) 874 972 37,698 112 1,536 — 6,044 2,570 93 — — 458 81 — 2,620 1,190 — 6,152 2,587 95 — — 334 37 — 2,839 1,452 — 4,858 2,193 97 — — 464 28 — 2,878 1,178 (1,791) 36,010 (25) 12,363 555 222 — 2 235 370 952 8,379 (361) 68 244 853 1,628 676 (462) 5,062 (120) 49,817 6,385 334,697 — 20,641 1,628 849 15,429 29,038 34,080 376,317 1,225 (1,663) 55,740 (23) 13,727 825 193 — 1 252 200 1,177 8,316 (368) 36 241 973 446 699 (1,162) 897 (113) 44,671 11,463 398,675 — 24,040 446 798 20,176 18,338 34,522 369,067 1,807 (2,636) 23,040 (36) 12,473 749 195 — 1 329 136 1,185 8,030 (354) 30 227 875 33 844 (1,054) 658 (337) 22,863 6,657 276,692 — 20,607 33 947 7,636 12,541 31,225 338,923 Due to rounding, numbers presented may not add up precisely to the totals indicated. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Revenue from Contracts with Customers Sales and other operating revenue include both revenue within the scope of ASC 606 and outside the scope of ASC 606. Revenue outside the scope of ASC 606 primarily relates to physically settled commodity contracts accounted for as derivatives. Contractual terms, credit quality, and type of customer are generally similar between contracts within the scope of ASC 606 and those outside it. Sales and other operating revenue (millions of dollars) Revenue from contracts with customers Revenue outside the scope of ASC 606 Total Geographic Sales and other operating revenue (millions of dollars) United States Non-U.S. Total Significant non-U.S. revenue sources include: Canada (1) United Kingdom Singapore France Australia Belgium Germany 2023 2022 2021 256,455 78,242 334,697 304,758 93,917 398,675 228,968 47,724 276,692 2023 2022 2021 127,374 207,323 334,697 149,225 249,450 398,675 104,236 172,456 276,692 28,994 23,372 15,331 14,803 9,883 9,840 9,297 32,970 33,988 19,029 17,727 11,316 11,279 10,190 22,166 14,759 15,031 13,236 7,646 9,153 7,565 (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) United States Non-U.S. Total Significant non-U.S. long-lived assets include: Canada Singapore Australia Guyana Kazakhstan Papua New Guinea United Arab Emirates Brazil China Nigeria Russia 113 December 31, 2023 2022 2021 95,792 119,148 214,940 90,051 114,641 204,692 90,412 126,140 216,552 31,682 12,490 11,212 9,689 7,728 7,433 5,480 4,203 3,669 3,319 — 31,106 11,972 11,372 6,766 8,172 7,338 5,448 3,649 2,350 4,090 — 34,907 11,969 12,988 4,892 8,463 7,534 5,392 4,337 984 5,235 4,055 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. Income and Other Taxes (millions of dollars) 2023 2022 2021 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 Deferred - net U.S. tax on non-U.S. operations Total federal and non-U.S. State Total income tax expense (benefit) All other taxes and duties Other taxes and duties Included in production and manufacturing expenses Included in SG&A expenses Total other taxes and duties Total 1,987 12,111 14,098 696 15,071 15,767 463 315 481 — 944 315 4,122 65 (539) — 3,583 65 2,765 12,592 15,357 4,883 14,532 19,415 72 2,837 — 12,592 72 15,429 761 5,644 — 14,532 761 20,176 236 870 26 1,132 470 1,602 6,948 7,184 (914) — 6,034 — 6,034 (44) 26 7,166 470 7,636 3,871 25,140 29,011 4,087 23,832 27,919 3,731 26,508 30,239 1,961 183 6,015 8,852 726 310 26,176 38,768 2,687 493 32,191 47,620 2,204 151 6,442 12,086 862 319 25,013 39,545 3,066 470 31,455 51,631 1,589 170 5,490 7,092 674 283 27,465 33,499 2,263 453 32,955 40,591 The above provisions for deferred income taxes include net expenses of $24 million in 2023, and $30 million in 2022, and net benefits of $53 million in 2021 related to changes in tax laws and rates. Additional European Taxes on the Energy Sector. On October 6, 2022, European Union (“EU”) Member States adopted an EU Council Regulation which, along with other measures, introduced a new tax described as an emergency intervention to address high energy prices. This regulation imposed a mandatory tax on certain companies active in the crude petroleum, coal, natural gas, and refinery sectors. The regulation required Member States to levy a minimum 33 percent tax on in-scope companies’ 2022 and/or 2023 “surplus profits", defined in the regulation as taxable profits exceeding 120 percent of the annual average profits during the 2018-2021 period. EU Member States were required to implement the tax, or an equivalent national measure, by December 31, 2022. The enactment of these regulations by Member States resulted in an after-tax charge of approximately $1.8 billion to the Corporation’s fourth-quarter 2022 results and approximately $0.2 billion in 2023, mainly reflected in the line “Income tax expense (benefit)” on the Consolidated Statement of Income. 114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2023, 2022, and 2021 is as follows: (millions of dollars) 2023 2022 2021 Income (loss) before income taxes United States Non-U.S. Total Theoretical tax Effect of equity method of accounting Non-U.S. taxes in excess of/(less than) theoretical U.S. tax State taxes, net of federal tax benefit (1) Other Total income tax expense (credit) Effective tax rate calculation Income tax expense (credit) ExxonMobil share of equity company income taxes Total income tax expense (credit) Net income (loss) including noncontrolling interests Total income (loss) before taxes Effective income tax rate 14,786 37,997 52,783 11,084 (1,341) 5,888 57 (259) 28,281 49,472 77,753 16,328 (2,407) 6,423 601 (769) 15,429 20,176 15,429 3,058 18,487 37,354 55,841 20,176 7,594 27,770 57,577 85,347 9,478 21,756 31,234 6,559 (1,398) 2,809 371 (705) 7,636 7,636 2,756 10,392 23,598 33,990 33% 33% 31% (1) Includes the impact of the additional European taxes on the energy sector of $1,825 million in 2022 and $115 million in 2023. 115 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities/(assets) are comprised of the following at December 31: Tax effects of temporary differences for: (millions of dollars) Property, plant and equipment Other liabilities Total deferred tax liabilities Pension and other postretirement benefits Asset retirement obligations Tax loss carryforwards Other assets Total deferred tax assets Asset valuation allowances Net deferred tax liabilities 2023 2022 26,627 7,534 34,161 (1,777) (3,532) (4,317) (6,361) 25,607 7,401 33,008 (1,754) (3,045) (4,862) (6,948) (15,987) (16,609) 2,641 20,815 2,650 19,049 In 2023, asset valuation allowances of $2,641 million decreased by $9 million and included net provisions of $104 million and foreign currency and other effects of $113 million. Balance sheet classification (millions of dollars) Other assets, including intangibles, net Deferred income tax liabilities Net deferred tax liabilities 2023 2022 (3,637) 24,452 20,815 (3,825) 22,874 19,049 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, 2023, 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. 116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits: Gross unrecognized tax benefits (millions of dollars) Balance at January 1 Additions based on current year's tax positions Additions for prior years' tax positions Reductions for prior years' tax positions Reductions due to lapse of the statute of limitations Settlements with tax authorities Foreign exchange effects/other Balance at December 31 2023 2022 2021 3,398 350 400 (38) (25) (153) 3 3,935 9,130 539 294 (6,243) (16) (277) (29) 3,398 8,764 358 100 (79) (2) (11) — 9,130 The gross unrecognized tax benefit balances are predominantly related 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 2023, 2022, and 2021 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 will take many years to complete. It is difficult to predict the timing of resolution for these tax positions since the timing is not entirely within the control of the Corporation. Unlike 2022, during which litigation resolved certain unrecognized tax benefit positions, there was no major resolution of unrecognized tax benefit positions in 2023. The Corporation has various U.S. federal income tax positions at issue with the Internal Revenue Service (IRS) for tax years beginning in 2010. Unfavorable resolution of these issues would not have a material adverse effect on the Corporation’s operations or financial condition. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent or decrease by up to 30 percent in the next 12 months. The following table summarizes the tax years that remain subject to examination by major tax jurisdiction: Country of Operation Open Tax Years Australia Belgium Canada Kazakhstan Nigeria Papua New Guinea United Arab Emirates United States 2010 — 2023 2020 — 2023 2001 — 2023 2015 — 2023 2016 — 2023 2008 — 2023 2022 — 2023 2010 — 2023 The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense. For 2023, 2022, and 2021 the Corporation's net interest expense on income tax reserves was $60 million, $16 million, and $0 million, respectively. The related interest payable balances were $134 million and $63 million at December 31, 2023 and 2022, respectively. 117 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 20. Divestment Activities In 2023, the Corporation realized proceeds of approximately $4.1 billion and recognized net after-tax earnings of approximately $0.6 billion from its divestment activities. This included the sale of the Aera Energy joint venture, Esso Thailand Ltd., the Billings Refinery, certain unconventional assets in the United States, as well as other smaller divestments. In 2022, the Corporation realized proceeds of approximately $5.2 billion and recognized net after-tax earnings of approximately $0.4 billion from its divestment activities. This included the sale of certain unproved assets in Romania and unconventional assets in Canada and the United States, as well as other smaller divestments. In February 2022, the Corporation signed an agreement with Seplat Energy Offshore Limited for the sale of Mobil Producing Nigeria Unlimited. The agreement is subject to certain conditions precedent and government approvals. In early July 2022, a Nigerian court issued an order to halt transition activities and enter into arbitration with the Nigerian National Petroleum Company. The closing date and any loss on sale will depend on resolution of these matters. On February 14, 2024, the Corporation closed the sale of the Santa Ynez Unit and associated facilities in California. The Corporation expects no material impacts on its first quarter 2024 financial statements. 118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 21. Mergers and Acquisitions 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 which consisted of proved reserves totaling approximately 0.2 billion oil-equivalent barrels and approximately 45 thousand oil-equivalent barrels per day of production. Total consideration was $5.1 billion, which included the issuance of 46 million shares of ExxonMobil common stock from treasury having a fair value of $4.8 billion on the acquisition date, and cash payments of $0.3 billion related to repayment of Denbury's credit facility and settlement of fractional shares. The transaction was accounted for as a business combination in accordance with ASC 805, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed: (billions of dollars) Current assets Property, plant & equipment Other assets Total assets Current liabilities Long-term liabilities Total liabilities Net assets acquired 0.4 6.4 0.2 7.0 0.3 1.6 1.9 5.1 Inputs for the assumptions used in the income approach to value property, plant and equipment included estimates for pipeline tariff rates, pipeline throughput volumes, commodity prices, future oil and gas production profiles, operating expenses, and a risk-adjusted discount rate. The Denbury acquisition resulted in an immaterial amount of goodwill. Revenues and earnings arising from Denbury's operations are immaterial in 2023 for pro forma disclosure purposes. Pioneer Natural Resources Company On October 11, 2023, the Corporation announced a merger agreement with Pioneer Natural Resources Company (Pioneer), an independent oil and gas exploration and production company, in exchange for ExxonMobil common stock. Based on the October 5 closing price for ExxonMobil shares, the fixed exchange rate of 2.3234 per Pioneer share, and Pioneer's outstanding net debt, the implied enterprise value of the transaction was approximately $65 billion. We expect the number of shares issuable in connection with the transaction to be approximately 546 million. The transaction is expected to close in the second quarter of 2024, subject to regulatory approvals. Pioneer holds over 850 thousand net acres in the Midland Basin of West Texas, which consist of proved reserves totaling over 2.3 billion oil-equivalent barrels (as of December 31, 2022) and over 700 thousand oil-equivalent barrels per day of production for the three months ended September 30, 2023. 119 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 $(519) million in 2023, $4,802 million in 2022 and $(1,380) million in 2021. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules. United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Results of Operations (millions of dollars) 2023 Consolidated Subsidiaries Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for consolidated subsidiaries Equity Companies Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for equity companies 5,098 13,378 18,476 4,164 44 8,479 1,701 703 3,385 182 83 265 239 — 58 12 — (44) 4,027 11,474 15,501 4,943 505 2,866 117 1,196 5,874 — — — — — — — — — 1,345 47 1,392 623 25 96 48 315 285 1,211 29 1,240 419 — 27 27 202 565 850 298 6,355 6,653 1,710 124 1,561 516 1,299 1,443 214 — 214 39 — 42 — 30 103 1,546 2,490 10,779 13,269 1,146 18 1,519 1,936 6,498 2,152 14,653 232 14,885 714 — 605 5,049 2,904 5,613 7,765 4,588 600 5,188 511 35 755 358 1,078 2,451 — — — — — — — — — 2,451 17,846 42,633 60,479 13,097 751 15,276 4,676 11,089 15,590 16,260 344 16,604 1,411 — 732 5,088 3,136 6,237 21,827 Total results of operations 3,341 5,874 120 United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Results of Operations (millions of dollars) 2022 Consolidated Subsidiaries Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for consolidated subsidiaries Equity Companies Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for equity companies 8,801 17,020 25,821 3,965 18 5,472 2,314 3,294 10,758 820 640 1,460 667 — 280 37 — 476 4,401 12,568 16,969 5,519 698 3,700 120 1,112 5,820 — — — — — — — — — Total results of operations 11,234 5,820 2021 Consolidated Subsidiaries Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for consolidated subsidiaries Equity Companies Sales to third parties Transfers Revenue Production costs excluding taxes Exploration expenses Depreciation and depletion Taxes other than income Related income tax Results of producing activities for equity companies Total results of operations 5,797 10,938 16,735 3,436 19 6,185 1,367 1,276 4,452 620 479 1,099 538 — 509 33 — 19 4,471 2,480 8,492 10,972 4,867 464 2,690 113 55 2,783 — — — — — — — — — 2,783 121 2,388 60 2,448 464 28 193 140 1,048 575 2,791 51 2,842 607 1 48 232 1,413 541 1,116 1,628 412 2,040 754 26 408 11 235 606 1,332 33 1,365 1,065 2 194 48 13 43 649 463 8,634 9,097 1,965 168 2,293 729 2,004 1,938 10 — 10 21 — 1 — (2) (10) 1,928 253 6,087 6,340 1,759 359 2,799 490 311 622 — — — 11 — — — 3 (14) 608 2,710 12,274 14,984 1,492 51 5,672 2,312 6,008 (551) 20,750 316 21,066 379 — 717 6,857 4,559 8,554 8,003 2,110 8,829 10,939 1,471 146 1,965 1,258 3,858 2,241 12,239 151 12,390 413 — 611 3,749 2,652 4,965 7,206 6,222 996 7,218 513 62 829 689 1,549 3,576 — — — — — — — — — 3,576 3,182 812 3,994 481 40 1,002 423 610 1,438 — — — — — — — — — 1,438 24,985 51,552 76,537 13,918 1,025 18,159 6,304 15,015 22,116 24,371 1,007 25,378 1,674 1 1,046 7,126 5,970 9,561 31,677 15,450 35,570 51,020 12,768 1,054 15,049 3,662 6,345 12,142 14,191 663 14,854 2,027 2 1,314 3,830 2,668 5,013 17,155 Oil and Gas Exploration and Production Costs The amounts shown for net capitalized costs of consolidated subsidiaries are $10,769 million less at year-end 2023 and $10,785 million less at year-end 2022 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) As of December 31, 2023 Consolidated Subsidiaries Property (acreage) costs – Proved – Unproved Total property costs Producing assets Incomplete construction Total capitalized costs Accumulated depreciation and depletion Net capitalized costs for consolidated subsidiaries Equity Companies Property (acreage) costs – Proved – Unproved Total property costs Producing assets Incomplete construction Total capitalized costs Accumulated depreciation and depletion Net capitalized costs for equity companies As of December 31, 2022 Consolidated Subsidiaries Property (acreage) costs – Proved – Unproved Total property costs Producing assets Incomplete construction Total capitalized costs Accumulated depreciation and depletion Net capitalized costs for consolidated subsidiaries Equity Companies Property (acreage) costs – Proved – Unproved Total property costs Producing assets Incomplete construction Total capitalized costs Accumulated depreciation and depletion Net capitalized costs for equity companies United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total 7 37 44 12,676 172 12,892 12,289 603 4 — 4 5,493 11 5,508 5,177 331 9 37 46 12,156 172 12,374 11,752 622 3 — 3 5,243 35 5,281 4,934 347 1,512 122 1,634 52,243 1,393 55,270 48,751 6,519 309 3,111 3,420 288 550 4,258 42 4,216 1,510 119 1,629 53,164 1,404 56,197 48,606 7,591 309 3,111 3,420 281 550 4,251 — 4,251 3,013 5 3,018 45,260 3,178 51,456 32,764 18,692 — — — 10,153 13,083 23,236 7,768 15,468 3,023 5 3,028 45,405 3,043 51,476 32,025 19,451 — — — 10,177 11,709 21,886 7,171 14,715 699 2,660 3,359 15,306 2,402 21,067 10,424 10,643 — — — — — — — — 695 2,659 3,354 14,296 2,276 19,926 9,548 10,378 — — — — — — — — 23,409 17,079 40,488 278,671 22,317 341,476 204,000 137,476 313 3,111 3,424 17,266 13,645 34,335 13,776 20,559 24,211 19,628 43,839 271,153 18,838 333,830 200,469 133,361 411 3,113 3,524 22,583 12,454 38,561 16,617 21,944 3,420 3,035 6,455 53,019 9,712 69,186 27,224 41,962 — — — — — — — — 3,427 3,011 6,438 49,923 7,774 64,135 25,852 38,283 — — — — — — — — 14,758 11,220 25,978 100,167 5,460 131,605 72,548 59,057 — — — 1,332 1 1,333 789 544 15,547 13,797 29,344 96,209 4,169 129,722 72,686 57,036 99 2 101 6,882 160 7,143 4,512 2,631 122 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 2023 were $20,952 million, up $6,439 million from 2022, due primarily to higher development costs and the Denbury acquisition. In 2022, costs were $14,513 million, up $4,636 million from 2021, due primarily to higher development costs. Total equity company costs incurred in 2023 were $1,510 million, down $259 million from 2022, due to lower development costs. Costs Incurred in Property Acquisitions, Exploration and Development Activities (millions of dollars) During 2023 Consolidated Subsidiaries Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for consolidated subsidiaries Equity Companies Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for equity companies During 2022 Consolidated Subsidiaries Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for consolidated subsidiaries Equity Companies Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for equity companies During 2021 Consolidated Subsidiaries Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for consolidated subsidiaries Equity Companies Property acquisition costs – Proved – Unproved Exploration costs Development costs Total costs incurred for equity companies United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total — — 23 55 78 — — — 5 5 — — 71 161 232 — — 1 13 14 — — 46 207 253 — — 1 20 21 2 6 117 562 687 — — — 7 7 151 — 145 533 829 — — — 22 22 90 — 185 389 664 — — — 88 88 — — 18 822 840 — — — 1,488 1,488 32 — 38 1,490 1,560 — — — 1,638 1,638 15 — 47 805 867 — — — 1,334 1,334 — — 35 1,046 1,081 — — — — — — 7 62 440 509 — — — — — — 35 40 435 510 — — — — — 2,458 177 940 17,377 20,952 — — — 1,510 1,510 204 26 1,079 13,204 14,513 — — 1 1,768 1,769 142 688 1,240 7,807 9,877 — — 1 1,450 1,451 — — 693 5,914 6,607 — — — — — 11 — 736 4,759 5,506 — — — — — — 575 903 2,619 4,097 — — — — — 2,456 171 54 8,978 11,659 — — — 10 10 10 19 27 5,821 5,877 — — — 95 95 37 78 19 3,352 3,486 — — — 8 8 123 Oil and Gas Reserves The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2021, 2022, and 2023. 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 the 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 2023 that were associated with production sharing contract arrangements was 13 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 2023 year-end proved reserves and 2022 year-end proved reserves include worldwide production of 1.4 billion oil-equivalent barrels (GOEB), asset sales of 0.2 GOEB primarily in the United States, and downward revisions of 0.4 GOEB. Additions to proved reserves include 1.1 GOEB from extensions and discoveries primarily in the United States and Guyana and 0.2 GOEB related to the Denbury acquisition. The changes between 2022 year-end proved reserves and 2021 year-end proved reserves include worldwide production of 1.4 GOEB, asset sales of 0.4 GOEB primarily in the United States, and other downward revisions of 1.2 GOEB including the impact of the Russia expropriation (0.2 GOEB). Additions to proved reserves include 0.7 GOEB from purchases in Asia and 1.4 GOEB from extensions and discoveries primarily in the United States and Guyana. The changes between 2021 year-end proved reserves and 2020 year-end proved reserves reflect upward revisions of 2.4 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake, primarily as a result of improved prices. In addition, extensions and discoveries of approximately 1.3 GOEB occurred primarily in the United States (0.9 GOEB), Brazil (0.2 GOEB) and Guyana (0.1 GOEB). Worldwide production in 2021 was 1.4 GOEB. 124 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves Crude Oil Natural Gas Liquids United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Worldwide Bitumen Canada/ Other Americas Synthetic Oil Canada/ Other Americas (millions of barrels) Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2021 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2021 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2021 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2021 Total liquids proved reserves at December 31, 2021 Net proved developed and undeveloped reserves of consolidated subsidiaries (1) January 1, 2022 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2022 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2022 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2022 Total liquids proved reserves at December 1,959 47 — 5 (27) 499 (176) 2,307 131 38 — — — 2 (16) 155 497 (2) — — (8) 329 (47) 769 9 — — — — — — — — 2,462 769 2,307 (375) — 1 (3) 465 (191) 2,204 155 (21) — — — — (15) 119 769 52 — — (12) 208 (72) 945 14 — — — — — — — — 31, 2022 Includes (118) million barrels in Russia which were expropriated. See Note 2: Russia. 2,323 945 (1) 74 10 — — — — (10) 74 — — — — — — — — 74 74 2 — — — — (10) 66 — — — — — — — — 66 22 15 — — (28) — (6) 3 9 2 — — — — (1) 10 13 3 3 — — — — (1) 5 10 (7) — — — — (1) 2 7 356 67 — — — — (88) 335 6 (1) — — — — — 5 3,150 36 — — — — (149) 3,037 825 (8) — — — — (76) 741 340 3,778 335 38 — — (17) — (85) 271 5 — — — — — — 5 3,037 (95) — — — — (148) 2,794 741 (17) — 110 — — (78) 756 276 3,550 125 6,058 173 — 5 (63) 828 (476) 6,525 971 31 — — — 2 (93) 911 1,054 4 — 1 (20) 183 (86) 1,136 1 277 15 — — — — (22) 270 81 2,944 2 — — — (133) 2,894 674 — — — — — — — — 444 17 — — — — (23) 438 133 — — — — — — — — Total 7,637 3,138 2 6 (83) 1,011 (718) 10,993 1,248 46 — — — 2 (115) 1,181 7,436 1,406 2,894 438 12,174 6,525 (375) — 1 (32) 673 (507) 6,285 911 (45) — 110 — — (94) 882 1,136 (85) — — (20) 235 (90) 1,176 270 (10) — 117 — — (22) 355 2,894 (422) — — — 67 (119) 2,420 554 — — — — — — — — 438 (62) — — — — (23) 353 107 — — — — — — — — 10,993 (944) — 1 (52) 975 (739) 10,234 1,181 (55) — 227 — — (116) 1,237 7,167 1,531 2,420 353 11,471 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) Crude Oil Natural Gas Liquids United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Worldwide Bitumen Canada/ Other Americas Synthetic Oil Canada/ Other Americas (millions of barrels) Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2023 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2023 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2023 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2023 Total liquids proved reserves at December 31, 2023 2,204 (398) — 156 (12) 355 (203) 2,102 119 — — — (108) — (4) 7 945 32 — — — 105 (88) 994 1 — — — — — — — — 2,109 994 5 — — — — — (1) 4 2 1 — — — — — 3 7 66 3 — — — — (8) 61 — — — — — — — — 61 271 31 — — — — (78) 224 5 — — — — — — 5 2,794 30 — — (4) — (153) 2,667 756 103 — — — — (79) 780 229 3,447 126 6,285 (302) — 156 (16) 460 (531) 6,052 882 104 — — (108) — (83) 795 1,176 (110) — 2 (5) 272 (99) 1,236 355 1 — — (1) — (22) 333 2,420 123 — — — — (129) 2,414 551 — — — — — — — — 353 26 — — — — (25) 354 108 — — — — — — — — Total 10,234 (263) — 158 (21) 732 (784) 10,056 1,237 105 — — (109) — (105) 1,128 6,847 1,569 2,414 354 11,184 Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) (millions of barrels) As of December 31, 2021 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total liquids proved reserves at December 31, 2021 As of December 31, 2022 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total liquids proved reserves at December 31, 2022 As of December 31, 2023 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total liquids proved reserves at December 31, 2023 Crude Oil and Natural Gas Liquids United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total Bitumen Canada/ Other Americas Synthetic Oil Canada/ Other Americas Total 1,663 133 1,621 28 3,445 1,688 126 1,568 — 3,382 1,735 11 1,498 — 3,244 268 — 508 — 776 378 — 568 — 946 433 — 561 — 994 3 10 — — 13 5 2 — — 7 4 3 — — 7 330 — 31 5 2,154 474 988 531 366 4,147 259 5 35 — 2,067 360 813 744 299 3,984 217 5 20 — 1,996 438 751 671 242 3,856 63 — 32 — 95 50 — 30 — 80 45 — 28 — 73 4,481 617 3,180 564 8,842 4,447 493 3,014 744 8,698 4,430 457 2,858 671 (1) 8,416 2,635 — 259 — 2,894 2,288 — 132 — 2,420 2,307 — 107 — 2,414 326 — 112 — 438 248 — 105 — 353 242 — 112 — 354 7,442 617 3,551 564 12,174 6,983 493 3,251 744 11,471 6,979 457 3,077 671 11,184 (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 2023 Form 10-K. 127 Natural Gas and Oil-Equivalent Proved Reserves Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total (millions of oil-equivalent barrels) Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2021 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2021 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2021 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2021 Total proved reserves at December 31, 2021 Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2022 (2) Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2022 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2022 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2022 Total proved reserves at December 31, 2022 13,439 1,432 — 3 (164) 1,381 (1,103) 14,988 102 44 — — — 5 (11) 140 15,128 14,988 (990) — 2 (1,551) 2,232 (1,036) 13,645 140 (3) — — — — (10) 127 13,772 561 305 — — (18) 163 (92) 919 124 — — — — — — — — 919 919 (38) — — (272) 175 (76) 708 77 — — — — — — — — 708 441 210 — — (120) — (148) 383 360 206 — — — — (158) 408 791 383 149 — — — — (119) 413 408 104 — — — — (132) 380 793 320 39 — — — — (42) 317 917 (111) — — — — — 806 1,123 317 49 — — (1) — (53) 312 806 (132) — — — — (11) 663 975 4,309 (276) — — — — (340) 3,693 11,377 (236) — — — — (983) 10,158 13,851 3,693 (307) — — — — (325) 3,061 10,158 29 — 3,101 — — (979) 12,309 15,370 6,134 712 — — — — (483) 6,363 — — — — — — — — 6,363 6,363 187 — — — — (542) 6,008 — — — — — — — — 6,008 25,204 2,422 — 3 (302) 1,544 (2,208) 26,663 12,756 (97) — — — 5 (1,152) 11,512 38,175 26,663 (950) — 2 (1,824) 2,407 (2,151) 24,147 11,512 (2) — 3,101 — — (1,132) 13,479 37,626 11,837 3,542 2 6 (134) 1,269 (1,086) 15,436 3,374 30 — — — 3 (307) 3,100 18,536 15,436 (1,102) — 1 (356) 1,376 (1,097) 14,258 3,100 (55) — 744 — — (305) 3,484 17,742 (1) (2) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. Includes (199) billion cubic feet of natural gas and (152) million total oil-equivalent barrels in Russia which were expropriated. See Note 2: Russia. 128 Natural Gas and Oil-Equivalent Proved Reserves (continued) Net proved developed and undeveloped reserves of consolidated subsidiaries January 1, 2023 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2023 Attributable to noncontrolling interests Proportional interest in proved reserves of equity companies January 1, 2023 Revisions Improved recovery Purchases Sales Extensions/discoveries Production December 31, 2023 Total proved reserves at December 31, 2023 Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total (millions of oil-equivalent barrels) 13,645 (1,945) — 7 (417) 1,930 (957) 12,263 127 (27) — — (35) — (8) 57 12,320 708 (201) — — (1) 67 (53) 520 26 — — — — — — — — 520 413 (3) — — — — (103) 307 380 18 — — — — (54) 344 651 312 (49) — — — — (43) 220 663 157 — — — — (40) 780 1,000 3,061 121 — — (9) — (379) 2,794 12,309 (32) — — — — (956) 11,321 14,115 6,008 339 — — — — (489) 5,858 — — — — — — — — 5,858 24,147 (1,738) — 7 (427) 1,997 (2,024) 21,962 13,479 116 — — (35) — (1,058) 12,502 34,464 14,258 (553) — 159 (92) 1,065 (1,121) 13,716 3,484 124 — — (115) — (281) 3,212 16,928 (1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. 129 Natural Gas and Oil-Equivalent Proved Reserves (continued) Natural Gas (billions of cubic feet) Oil-Equivalent Total All Products (1) United States Canada/ Other Americas Europe Africa Asia Australia/ Oceania Total (millions of oil-equivalent barrels) As of December 31, 2021 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total proved reserves at December 31, 2021 As of December 31, 2022 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total proved reserves at December 31, 2022 As of December 31, 2023 Proved developed reserves Consolidated subsidiaries Equity companies Proved undeveloped reserves Consolidated subsidiaries Equity companies Total proved reserves at December 31, 2023 11,287 117 3,701 23 15,128 9,577 127 4,068 — 13,772 8,138 57 4,125 — 12,320 574 — 345 — 919 371 — 337 — 708 329 — 191 — 520 377 339 6 69 791 408 326 5 54 793 307 290 — 54 651 315 — 2 806 1,123 307 663 5 — 975 220 780 — — 1,000 2,527 6,017 1,166 4,141 13,851 2,037 5,020 1,024 7,289 15,370 1,935 4,223 859 7,098 14,115 3,513 — 2,850 — 6,363 3,162 — 2,846 — 6,008 3,163 — 2,695 — 5,858 18,593 6,473 8,070 5,039 38,175 15,862 6,136 8,285 7,343 37,626 14,092 5,350 7,870 7,152 34,464 10,540 1,696 4,896 1,404 18,536 9,627 1,516 4,631 1,968 17,742 9,327 1,349 4,389 1,863 16,928 (1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. 130 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) As of December 31, 2021 Consolidated Subsidiaries Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows Equity Companies Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows United States Canada/Other Americas (1) Europe Africa Asia Australia/ Oceania Total 217,023 63,464 29,941 24,770 98,848 50,524 48,324 10,607 5,005 2,340 — 3,262 1,553 1,709 209,711 111,468 31,736 12,004 54,503 25,793 28,710 — — — — — — — 4,322 1,142 2,113 451 616 (502) 1,118 5,889 785 1,137 1,793 2,174 683 1,491 24,812 7,700 5,921 4,319 6,872 739 6,133 4,553 261 62 1,168 3,062 1,868 1,194 211,255 55,241 14,519 107,577 33,918 17,383 16,535 146,845 49,810 8,317 29,463 59,255 25,710 33,545 69,015 14,880 7,286 13,038 33,811 18,751 15,060 — — — — — — — 736,138 253,895 91,516 162,159 228,568 112,688 115,880 167,894 55,861 11,856 32,424 67,753 29,814 37,939 Total consolidated and equity interests in standardized measure of discounted future net cash flows 50,033 28,710 2,609 7,327 50,080 15,060 153,819 (1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $3,666 million in 2021. 131 Standardized Measure of Discounted Future Cash Flows (continued) (millions of dollars) As of December 31, 2022 Consolidated Subsidiaries Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows Equity Companies Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows United States Canada/Other Americas (1) Europe Africa Asia Australia/ Oceania Total 316,486 78,939 31,960 45,278 160,309 83,711 76,598 12,312 5,379 1,773 — 5,160 2,236 2,924 284,643 113,264 34,968 31,603 104,808 49,861 54,947 — — — — — — — 11,806 2,627 2,016 3,164 3,999 187 3,812 13,706 1,981 895 5,262 5,568 2,234 3,334 30,040 7,489 6,143 8,300 8,108 322 7,786 7,194 266 60 1,965 4,903 2,694 2,209 271,732 63,705 9,241 156,595 42,191 21,772 20,419 261,409 96,788 7,275 51,838 105,508 44,728 60,780 114,959 21,972 7,089 24,955 60,943 34,896 26,047 — — — — — — — 1,029,666 287,996 91,417 269,895 380,358 190,749 189,609 294,621 104,414 10,003 59,065 121,139 51,892 69,247 Total consolidated and equity interests in standardized measure of discounted future net cash flows 79,522 54,947 7,146 9,995 81,199 26,047 258,856 As of December 31, 2023 Consolidated Subsidiaries Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows Equity Companies Future cash inflows from sales of oil and gas Future production costs Future development costs Future income tax expenses Future net cash flows Effect of discounting net cash flows at 10% Discounted future net cash flows 213,623 68,753 37,784 14,270 92,816 49,199 43,617 818 503 75 — 240 76 164 227,365 113,875 38,436 15,973 59,081 23,471 35,610 — — — — — — — 3,918 1,611 1,881 509 (83) (762) 679 5,101 982 697 1,539 1,883 672 1,211 19,282 5,025 4,466 4,337 5,454 402 5,052 4,393 233 100 1,120 2,940 1,635 1,305 221,822 52,672 11,926 121,751 35,473 18,537 16,936 158,643 73,496 5,452 24,374 55,321 20,135 35,186 63,204 13,971 6,393 12,119 30,721 16,215 14,506 — — — — — — — 749,214 255,907 100,886 168,959 223,462 107,062 116,400 168,955 75,214 6,324 27,033 60,384 22,518 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 $6,596 million in 2022 and $3,055 million in 2023. 132 Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Consolidated and Equity Interests (millions of dollars) Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests 2021 Discounted future net cash flows as of December 31, 2020 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs Development costs incurred during the year Net change in prices, lifting and development costs Revisions of previous reserves estimates Accretion of discount Net change in income taxes Total change in the standardized measure during the year Discounted future net cash flows as of December 31, 2021 26,554 11,922 (35,813) 7,033 118,946 27,126 3,762 (43,650) 89,326 115,880 8,441 22 (9,948) 1,563 47,434 2,507 1,201 (13,281) 29,498 37,939 34,995 11,944 (45,761) 8,596 166,380 29,633 4,963 (56,931) 118,824 153,819 Consolidated and Equity Interests (millions of dollars) Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests 2022 Discounted future net cash flows as of December 31, 2021 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs Development costs incurred during the year Net change in prices, lifting and development costs Revisions of previous reserves estimates Accretion of discount Net change in income taxes Total change in the standardized measure during the year Discounted future net cash flows as of December 31, 2022 115,880 18,592 (57,344) 11,834 139,844 (1,985) 14,655 (51,867) 73,729 189,609 37,939 3,008 (17,037) 1,849 51,094 2,140 4,938 (14,684) 31,308 69,247 153,819 21,600 (74,381) 13,683 190,938 155 19,593 (66,551) 105,037 258,856 Consolidated and Equity Interests (millions of dollars) Consolidated Subsidiaries Share of Equity Method Investees Total Consolidated and Equity Interests 2023 Discounted future net cash flows as of December 31, 2022 Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs Changes in value of previous-year reserves due to: Sales and transfers of oil and gas produced during the year, net of production (lifting) costs Development costs incurred during the year Net change in prices, lifting and development costs Revisions of previous reserves estimates Accretion of discount Net change in income taxes Total change in the standardized measure during the year Discounted future net cash flows as of December 31, 2023 189,609 5,658 (43,836) 15,343 (120,924) 4,953 23,006 42,591 (73,209) 116,400 69,247 (1,701) (10,218) 1,502 (51,923) 5,096 8,962 16,901 (31,381) 37,866 258,856 3,957 (54,054) 16,845 (172,847) 10,049 31,968 59,492 (104,590) 154,266 133 Exhibit 2.1 3(i) 3(ii) 4(vi) 10(iii)(a.1) 10(iii)(a.2) 10(iii)(a.3) 10(iii)(b.1) 10(iii)(b.2) 10(iii)(b.3) 10(iii)(c.1) 10(iii)(c.2) 10(iii)(c.3) 10(iii)(d) 10(iii)(f.1) 10(iii)(f.2) 10(iii)(f.3) 10(iii)(f.4) 10(iii)(g) 14 21 23 31.1 31.2 31.3 32.1 INDEX TO EXHIBITS Description Agreement and Plan of Merger, dated as of October 10, 2023 among Exxon Mobil Corporation, SPQR, LLC and Pioneer Natural Resources Company (incorporated by reference to Exhibit 2.1 to the Registrant’s Report on Form 8-K of October 11, 2023). ** Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015). By-Laws, as amended effective October 25, 2022 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of October 31, 2022). Description of ExxonMobil Capital Stock (incorporated by reference to Exhibit 4(vi) to the Registrant's Annual Report on Form 10-K for 2019). 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).* 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).* Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.* Short Term Incentive Program, as amended.* 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).* 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).* 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).* 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).* ExxonMobil Additional Payments Plan.* 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).* 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).* 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).* Form of restricted stock grant letter for non-employee directors.* Standing resolution for non-employee director cash fees dated March 1, 2020 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2020).* Aircraft Time Share Agreement dated as of August 29, 2023, between Exxon Mobil Corporation and Darren W. Woods (incorporated by reference to Exhibit 10(iii)(g) to the Registrant’s Report on Form 10-Q for the quarter ended October 31, 2023).* Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2017). Subsidiaries of the registrant. Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer. Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Financial Officer. Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer. Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer. Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Financial Officer. 32.2 Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer. 32.3 Policy Relating to Recovery of Erroneously Awarded Compensation. 97 Interactive data files (formatted as Inline XBRL). 101 104 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. ** Schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplementally to the SEC upon request. 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. 134 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. SIGNATURES Dated February 28, 2024 EXXON MOBIL CORPORATION By: /s/ DARREN W. WOODS Darren W. Woods, Chairman of the Board POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Jim E. Parsons, Brian J. Conjelko, and Antony E. Peters and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10- K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 28, 2024. Principal Executive Officer Directors /s/ DARREN W. WOODS Darren W. Woods, Chairman of the Board /s/ MICHAEL J. ANGELAKIS Michael J. Angelakis /s/ JOSEPH L. HOOLEY Joseph L. Hooley Principal Financial Officer /s/ SUSAN K. AVERY Susan K. Avery /s/ STEVEN A. KANDARIAN Steven A. Kandarian /s/ KATHRYN A. MIKELLS Kathryn A. Mikells, Senior Vice President and Chief Financial Officer /s/ ANGELA F. BRALY Angela F. Braly /s/ ALEXANDER A. KARSNER Alexander A. Karsner Principal Accounting Officer /s/ LEN M. FOX Len M. Fox, Vice President and Controller /s/ GREGORY J. GOFF Gregory J. Goff /s/ LAWRENCE W. KELLNER Lawrence W. Kellner /s/ JOHN D. HARRIS II John D. Harris II /s/ DINA POWELL MCCORMICK Dina Powell McCormick /s/ KAISA H. HIETALA Kaisa H. Hietala /s/ JEFFREY W. UBBEN Jeffrey W. Ubben 135 Exxon Mobil Corporation 2023 Extended Provisions for Restricted Stock Unit Agreements Settled in Stock EXHIBIT 10(iii)(a.3) 1. Effective Date and Credit of Restricted Stock Units. If Grantee accepts the award on or before March 1, 2024, this Agreement will become effective the date the Corporation receives the award acceptance. After this agreement becomes effective, the Corporation will credit to Grantee the number of restricted stock units specified in the Incentive Award Summary. Subject to the terms and conditions of this Agreement, each restricted stock unit ("unit") will entitle Grantee to receive in settlement of the unit one share of the Corporation's common stock. 2. Conditions. If credited, the units will be subject to the provisions of this Agreement, and to such regulations and requirements as the administrative authority of the Program may establish from time to time. The units will be credited to Grantee only on the condition that Grantee accepts such provisions, regulations, and requirements. 3. Restrictions and Risk of Forfeiture. During the applicable restricted periods specified in section 4 of this Agreement, (a) the units under restriction may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and any attempt to do so will be null and void; and, (b) the units under restriction may be forfeited as provided in section 6. 4. Restricted Periods. The restricted periods will commence when the units are credited to Grantee and, unless the units have been forfeited earlier under section 6, will expire as follows, whether or not Grantee is still an employee, (a) with respect to 50% of the units on November 29, 2028, and, (b) with respect to the remaining units on November 29, 2033, except that (c) the restricted periods will automatically expire with respect to all units on the death of Grantee. 5. No Obligation to Credit Units. The Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if Grantee fails to accept the award on or before March 1, 2024. In addition, whether or not Grantee has accepted the award, the Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if, before the units are credited, (a) Grantee terminates (other than by death) before standard retirement time within the meaning of the Program, except to the extent the administrative authority of the Program determines Grantee may receive units under this Agreement; or (b) Grantee is determined to have engaged in detrimental activity within the meaning of the Program. 6. Forfeiture of Units After Crediting. Until the applicable restricted period specified in section 4 has expired, the units under restriction will be forfeited or subject to forfeiture in the following circumstances: • Termination - If Grantee terminates (other than by death) before standard retirement time within the meaning of the Program, all units for which the applicable restricted periods have not expired will be automatically forfeited as of the date of termination, except to the extent the administrative authority determines Grantee may retain units issued under this Agreement. • Detrimental Activity - If Grantee is determined to have engaged in detrimental activity within the meaning of the Program, either before or after termination, all units for which the applicable restricted periods have not expired will be automatically forfeited as of the date of such determination. • Attempted Transfer - The units are subject to forfeiture at the discretion of the administrative authority if Grantee attempts to sell, assign, transfer, pledge, or otherwise dispose of or encumber them during the applicable restricted periods. 1 • Applicable Law - The units are subject to forfeiture in whole or in part as the administrative authority deems necessary to comply with applicable law or Corporation policy including, without limitation, any clawback obligations determined to be owed by Grantee to the Corporation in connection with this or other awards. 7. Taxes. Notwithstanding the restrictions on transfer that otherwise apply, the Corporation in its sole discretion may withhold units, or shares otherwise deliverable in settlement of units, either at the time of crediting, at the time of settlement, or at any other time in order to satisfy any required withholding, Social Security, and similar taxes or contributions (collectively, "required taxes"). Withheld units or shares may be retained by the Corporation or sold on behalf of Grantee. The Corporation in its sole discretion may also withhold any required taxes from dividend equivalents paid on the units. 8. Form of Units; No Shareholder Status. The units will be represented by book-entry credits in records maintained by or on behalf of the Corporation. Units will be unfunded and unsecured promises by the Corporation to deliver shares in the future upon the terms and subject to the conditions of this Agreement. Grantee will not be a shareholder of the Corporation with respect to units. 9. Settlement of Units. If and when the applicable restricted period expires with respect to any units, subject to section 7, the Corporation will issue shares, free of restriction and registered in the name of Grantee, in settlement of such units. Such shares will be delivered promptly after such expiration to or for the account of Grantee either in certificated form or by book-entry transfer in accordance with the procedures of the administrative authority in effect at the time 10. Dividend Equivalents. The Corporation will pay to Grantee cash with respect to each credited unit corresponding in amount, currency, and timing to cash dividends that would be payable with respect to a share of common stock outstanding on each record date that occurs during the applicable restricted period. Alternatively, the administrative authority may determine to reinvest such dividend equivalents in additional units which will be held subject to all the terms and conditions otherwise applicable to units under this Agreement. 11. Change in Capitalization. If during the applicable restricted periods a stock split, stock dividend, or other relevant change in capitalization of the Corporation occurs, the administrative authority will make such adjustments in the number of units credited to Grantee, or in the number and type of securities deliverable to Grantee in settlement of such units and used in determining dividend equivalent amounts, as the administrative authority may determine to be appropriate. Any resulting new units or securities credited with respect to previously credited units that are still restricted under this Agreement will be delivered to and held by or on behalf of the Corporation and will be subject to the same provisions, restrictions, and requirements as those previously credited units. 12. Limits on the Corporation’s Obligations. Notwithstanding anything else contained in this Agreement, under no circumstances will the Corporation be required to credit any units or issue or deliver any shares in settlement of units if doing so would violate any law or listing requirement that the administrative authority determines to be applicable. 13. Receipt or Access to Program. Grantee acknowledges receipt of or access to the full text of the Program. 14. Addresses for Communications. To facilitate communications regarding this Agreement, Grantee agrees to notify the Corporation promptly of changes in current mailing and e-mail addresses. Communications to the Corporation in connection with this Agreement should be directed to the Incentive Processing Office or to such other address as the Corporation may designate by further notice to Grantee. 15. Transfer of Personal Data. The administration of the Program and this Agreement, including any subsequent ownership of shares; involves the collection, use, and transfer of personal data about Grantee between and among the Corporation, selected subsidiaries and other affiliates of the Corporation, and third-party service providers such as Morgan Stanley and Computershare (the Corporation's transfer agent), as well as various regulatory and tax authorities around the world. This data includes Grantee's name, age, date of birth, contact information, work location, employment status, tax status, Social Security number, salary, nationality, job title, 2 share ownership, and details of incentive awards granted, cancelled, vested or unvested, and related information. By accepting this award, Grantee authorizes such collection, use, and transfer of this data. Grantee may, at any time and without charge, view such data and require necessary corrections to it. Such data will at all times be held in accordance with applicable laws, regulations, and agreements. For more information on data privacy, see the data privacy statement on the Incentive Award Program website. 16. No Employment Contract or Entitlement to Other or Future Awards. This Agreement, the Corporation's incentive programs, and Grantee's selection for incentive awards do not imply or form a part of any contract or assurance of employment, and they do not in any way limit or restrict the ability of Grantee's employer to terminate Grantee's employment. Grantee acknowledges that the Corporation maintains and administers its incentive programs entirely in its discretion and that Grantee is not entitled to any other or future incentive awards of any kind in addition to those that have already been granted. 17. Governing Law and Consent to Jurisdiction. This Agreement and the Program are governed by the laws of the State of New York without regard to any conflict of law rules. Any dispute arising out of or relating to this Agreement or the Program may be resolved in any state or federal court located within Harris County, Texas, U.S.A. Grantee accepts that venue and submits to the personal jurisdiction of any such court. Similarly, the Corporation accepts such venue and submits to such jurisdiction. 18. Entire Agreement. This Agreement together with the applicable electronically signed acceptance constitutes the entire understanding between Grantee and the Corporation with respect to the subject matter of this Agreement. 3 EXXON MOBIL CORPORATION SHORT TERM INCENTIVE PROGRAM (as amended October 23, 2023) EXHIBIT 10(iii)(b.1) I. Purposes The Short Term Incentive Program is intended to help reward, retain, and motivate selected employees of the Corporation and its affiliates by recognizing efforts and accomplishments which contribute materially to the success of the Corporation's business interests. II. Definitions In this Program, except where the context otherwise indicates, the following definitions apply: (1) "Administrative authority" means the Board, a committee designated by the Board, the Chairman of the Board, or the Chairman's delegates authorized to administer outstanding awards under this Program, establish requirements and procedures for the operation of the Program, and to exercise other powers assigned to the administrative authority under this Program. (2) "Affiliate" means a corporation, partnership, limited liability company, or other entity in which the Corporation, directly or indirectly, owns an equity interest and which the administrative authority determines to be an affiliate for purposes of this Program (including for purposes of determining whether a change of employment constitutes a termination). (3) "Award" means a bonus, bonus unit, or other award under this Program. (4) "Board" means the Board of Directors of the Corporation. (5) "Bonus" means a cash award specific in amount. (6) "Bonus unit" means a potential cash award whose amount is based upon specified measurement criteria. The term bonus unit includes, but is not limited to, earnings bonus units. (7) "Compensation Committee" means the committee of the Board so designated. (8) "Corporation" means Exxon Mobil Corporation, a New Jersey corporation, or its successors. (9) "Designated beneficiary" means a person designated by the grantee of an award pursuant to Section XIII to be entitled, on the death of the grantee, to any remaining rights arising out of such award. (10) "Detrimental activity" of a grantee means activity at any time, during or after employment with the Corporation or an affiliate, that is determined in individual cases by the administrative authority to be (a) a material violation of applicable standards, policies, or procedures of the Corporation or an affiliate; or (b) a material breach of legal or other duties owed by the grantee to the Corporation or an affiliate; or (c) a material breach of any contract between the grantee and the Corporation or an affiliate; or (d) acceptance by grantee of duties to a third party under circumstances that create a material conflict of interest, or the appearance of a material conflict of interest, with respect to the grantee's retention of outstanding awards under this Program. Detrimental activity includes, without limitation, activity that would be a basis for termination of employment for cause under applicable law in the United States, or a comparable standard under applicable law of another jurisdiction. With respect to material conflict of interest or the appearance of material conflict of interest, such conflict or appearance might occur when, for example and without limitation, a grantee holding an outstanding award becomes employed or otherwise engaged by an entity that regulates, deals with, or competes with the Corporation or an affiliate. (11) "Earnings bonus unit" or "EBU" means an award of the potential right to receive from the Corporation at the settlement date specified in the award instrument, or at any later payment dates so specified, an amount of cash, up to the specified maximum settlement value, equal to the Corporation's cumulative earnings per common share, as reflected in its quarterly earnings statements as initially filed in its quarterly or annual reports with the U.S. Securities and Exchange Commission, commencing with earnings for the first full quarter after the date of grant through the last full quarter preceding the settlement date. (12) "Employee" means an employee of the Corporation or an affiliate, including a part-time employee or an employee on military, family, or other approved temporary leave. (13) "Exchange Act" means the Securities Exchange Act of 1934, as in effect from time to time. (14) "Grantee" means a recipient of an award under this Program. (15) "Granting authority" means the Board or any appropriate committee authorized to grant and amend awards under this Program and to exercise other powers assigned to the granting authority. (16) "Net Income Per Common Share (Basic)" means net income per common share or earnings per share, as applicable. (17) "Program" means this Short Term Incentive Program, as amended from time to time. (18) "Reporting person" means a person subject to the reporting requirements of Section 16(a) of the Exchange Act. (19) "Resign" means to terminate at the initiative of the employee before standard retirement time. Resignation includes, without limitation, early retirement at the initiative of the employee. The time or date of a resignation for purposes of this Program is not necessarily the employee's last day on the payroll. See Section XI(2). (20) "Section 16" means Section 16 of the Exchange Act, together with the rules and interpretations thereunder, as in effect from time to time. (21) "Standard retirement time" means (a) for each US-dollar payroll employee, the first day of the month immediately following the month in which the employee attains age 65; and (b) for each other employee, the comparable age in that employee's payroll country as determined by the administrative authority with reference to local law, custom, and affiliate policies regarding retirement. (22) "Terminate" means cease to be an employee for any reason, whether at the initiative of the employee, the employer, or otherwise. That reason could include, without limitation, resignation or retirement by the employee; discharge of the employee by the employer, with or without cause; death; transfer of employment to an entity that is a not an affiliate; or a sale, divestiture, or other transaction as a result of which an employer ceases to be an affiliate. A change of employment from the Corporation or one affiliate to another affiliate, or to the Corporation, is not a termination. The time or date of termination is not necessarily the employee's last day on the payroll. See Section XI(2). (23) "Year" means calendar year. III. Administration The Board is the ultimate administrative authority for this Program, with the power to interpret and administer its provisions. The Board may delegate its authority to a committee which, except in the case of the Compensation Committee, need not be a committee of the Board. Subject to the authority of the Board or an authorized committee, the Chairman and his delegates will serve as the administrative authority for purposes of establishing requirements and procedures for the operation of this Program; making final determinations and interpretations with respect to outstanding awards; and exercising other powers assigned to the administrative authority under this Program. IV. No Equity-Security Awards It is intended that this Program not be subject to the provisions of Section 16 and that awards granted hereunder not be considered equity securities of the Corporation within the meaning of Section 16. Accordingly, no award under this Program will be payable in any equity security of the Corporation. In the event an award to a reporting person under this Program should be deemed to be an equity security of the Corporation within the meaning of Section 16, such award may, to the extent permitted by law and deemed advisable by the granting authority, be amended so as not to constitute such an equity security, or may be annulled. Each award to a reporting person under this Program will be deemed issued subject to the foregoing qualification. V. Annual Ceiling In respect to each year under this Program, the Compensation Committee will, pursuant to authority delegated by the Board, establish a ceiling on the aggregate dollar amount that can be awarded under this Program. With respect to bonuses and bonus units granted in a particular year under this Program, the sum of (1) the aggregate amount of bonuses, and (2) the aggregate maximum settlement value of bonus units will not exceed such ceiling. The Compensation Committee may revise the ceiling from time to time as it deems appropriate. VI. Right to Grant Awards; Reserved Powers; Eligibility (1) The Board is the ultimate granting authority for this Program, with the power to select eligible persons for participation and to make all decisions concerning the grant or amendment of awards. The Board may delegate this authority in whole or in part (a) in the case of reporting persons, to the Compensation Committee; and (b) in the case of employees who are not reporting persons, to a committee of two or more persons who may, but need not, be directors of the Corporation. (2) The granting authority has sole discretion to select persons for awards under this Program, except that grants may be made only to persons who at the time of grant are, or within the immediately preceding 12 months have been, employees of the Corporation or of an affiliate in which the Corporation directly or indirectly holds a 50 percent or greater equity interest. No person is entitled to an award as a matter of right, and the grant of an award under this Program does not entitle a grantee to any future or additional awards. (3) No award may be granted to a member of the Compensation Committee. VII. Term This Program will continue until terminated by the Board. VIII. Form of Bonus A bonus may be granted either wholly in cash, wholly in bonus units, or partly in each. IX. Settlement of Bonuses Each grant will specify the time and method of settlement as determined by the granting authority. Each grant, any portion of which is in bonus units, will specify as the regular time of settlement for that portion a settlement date, which may be accelerated to an earlier time specified in the award instrument. X. Deferred and Installment Settlement; Interest Equivalents (1) The granting authority may permit or require settlement of any award under this Program to be deferred and to be made in one or more installments upon such terms and conditions as the granting authority may determine at the time the award is granted or by amendment of the award, provided that settlement may not be made later than the tenth anniversary of the grantee's date of termination. (2) An award that is to be settled in whole or in part in cash on a deferred basis may provide for interest equivalents to be credited with respect to the deferred cash payment or payments upon such terms and conditions as the granting authority determines. Interest equivalents may be paid currently or may be added to the balance of the award amount and compounded, as specified in the award instrument. Compounded interest equivalents will be paid in cash upon settlement or payment of the underlying award and will expire or be forfeited or cancelled upon the same conditions as the underlying award. The granting authority may delegate to the administrative authority the right to determine the rate or rates at which interest equivalents will accrue. (3) Credits of interest equivalents on outstanding awards are not new grants with reference to the eligibility provisions of Section VI(2). (4) Credits of interest equivalents will not be included in any computation to establish compliance with a ceiling established by the Compensation Committee pursuant to Section V. XI. Termination; Detrimental Activity (1) If a grantee terminates before standard retirement time, other than by reason of death, all outstanding awards of the grantee under this Program (including bonuses, bonus units, EBUs, and other awards not yet paid or settled) will automatically expire and be forfeited as of the date of termination except to the extent the administrative authority (which, in the case of reporting persons, must be the Compensation Committee) determines otherwise. (2) For purposes of this Program, the administrative authority may determine that the time or date an employee resigns or otherwise terminates is the time or date the employee gives notice of resignation, accepts employment with another employer, otherwise indicates an intent to resign, or is discharged. The time or date of termination for this purpose is not necessarily the employee's last day on the payroll. (3) If the administrative authority (which, in the case of reporting persons, must be the Compensation Committee) determines that a grantee has engaged in detrimental activity, whether or not the grantee is still an employee, then the administrative authority may, effective as of the time of such determination, cancel and cause to expire all or part of the grantee's outstanding awards under this Program (including bonuses, bonus units, EBUs, and other awards not yet paid or settled). (4) If the administrative authority is advised or has reason to believe that a grantee (a) may have engaged in detrimental activity; or (b) may have accepted employment with another employer or otherwise indicated an intent to resign, the authority may suspend the exercise, delivery, or settlement of all or any specified portion of such grantee's outstanding awards pending an investigation of the matter. XII. Material Negative Restatement (1) Awards under this Program to “Covered Executives,” as defined in the Corporation’s Rule 10D-1 Recoupment Policy are subject to recovery in accordance with the terms of such Policy as in effect from time to time. (2) In addition to the right of recovery referenced in paragraph (1) of this Section XII, if the Corporation's reported financial or operating results become subject to a material negative restatement, the Compensation Committee in its sole discretion may require any current or former reporting person, as defined in Section II(18), to pay to the Corporation an amount corresponding to each award to that person under this Program, or portion of such award, that the Compensation Committee determines would not have been granted or paid if the Corporation's results as originally published had been equal to the Corporation's results as subsequently restated, provided that (a) any requirement or claim under this Section XII(2) will apply only with respect to grantees who were reporting persons at the time the applicable amounts were awarded or paid; (b) any requirement or claim under this Section XII(2) must be made, if at all, within five years after the date the amount claimed was originally paid by the Corporation; and (c) no amount may be recovered under the discretionary provisions of this Section XII(2) to the extent such amounts are also subject to recovery under the Policy referenced in Section XII(1). (3) The obligations of reporting persons to make payments under this Section XII are independent of any involvement by those reporting persons in events that led to the restatement. The provisions of this Section XII are in addition to, not in lieu of, any remedies that the Corporation may have against any persons whose misconduct caused or contributed to a need to restate the Corporation's reported results. XIII. Death; Beneficiary Designation Any rights and obligations of a grantee under this Program in effect at that grantee's death will apply to that grantee's designated beneficiary or, if there is no designated beneficiary, to that grantee's estate representative or lawful heirs, as demonstrated to the satisfaction of the administrative authority. Beneficiary designations must be made in writing and in accordance with such requirements and procedures as the administrative authority may establish. Unless specified otherwise in the award instrument, if a grantee dies, the administrative authority may accelerate or otherwise alter the settlement of deferred awards to that grantee. XIV. Amendments to this Program and Outstanding Awards (1) The Board may from time to time amend this Program. An amendment of this Program will, unless the amendment provides otherwise, be immediately and automatically effective for all outstanding awards. (2) Without amending this Program, the granting authority may amend any one or more outstanding awards under this Program to incorporate in those awards any terms that could be incorporated in a new award under this Program. An award as amended must satisfy any conditions or limitations applicable to the particular type of award under the terms of this Program. XV. Withholding Taxes The Corporation has the right, in its sole discretion, to deduct or withhold at any time cash otherwise payable or deliverable in order to satisfy any required withholding, social security, and similar taxes and contributions with respect to awards under this Program. XVI. Non-US Awards Subject to the limitations contained in this Program, the granting authority may establish different terms and conditions for awards to persons who are residents or nationals of countries other than the United States in order to accommodate the local laws, tax policies, or customs of such countries. The granting authority may adopt one or more supplements or sub-plans under this Program to implement those different terms and conditions. XVII. General Provisions (1) An award under this Program is not transferable except by will or the laws of descent and distribution, and is not subject to attachment, execution, or levy of any kind. The designation by a grantee of a designated beneficiary is not a transfer for this purpose. (2) A particular form of award may be granted to a grantee either alone or in addition to other awards hereunder. The provisions of particular forms of award need not be the same for each grantee. (3) An award may be granted for no consideration, for the minimum consideration required by applicable law, or for such other consideration as the granting authority may determine. (4) An award may be evidenced in such manner as the administrative authority determines, including by physical instrument, by electronic communication, or by book entry. In the event of any dispute or discrepancy regarding the terms of an award, the records of the administrative authority will be determinative. (5) The grant of an award under this Program does not constitute or imply a contract of employment and does not in any way limit or restrict the ability of the employer to terminate the grantee's employment, with or without cause, even if such termination results in the expiration, cancellation, or forfeiture of outstanding awards. (6) A grantee will have only a contractual right to the amounts, if any, payable in settlement of an award under this Program, unsecured by any assets of the Corporation or any other entity. (7) This Program will be governed by the laws of the State of New York and the United States of America, without regard to any conflict of law rules. EXXONMOBIL ADDITIONAL PAYMENTS PLAN 1. Purpose EXHIBIT 10(iii)(c.3) The purpose of this Plan is to provide additional payments from the general assets of Exxon Mobil Corporation (the "Corporation") to certain persons. The benefits payable under this Plan consist of two types of pension benefits and a disability benefit. The first pension benefit is a benefit based upon the person's final average incentive compensation ("Incentive Pension Benefit"). The second pension benefit restores certain benefits that are accrued under a pension plan sponsored by a non-U.S. affiliate of the Corporation but which are not paid ("Overseas Makeup Benefit"). The disability benefit is based on incentive compensation and is paid in the event of a long-term disability ("Disability Benefit"). 2.1 Eligibility 2. Incentive Pension Benefits A person is eligible to receive Incentive Pension Benefits only if any one of the following requirements is met with respect to the person: (A) the person becomes a retiree within the meaning of the ExxonMobil Common Provisions ("Retiree"); (B) the person’s employment is terminated in connection with a sale of the assets to a buyer or the outsourcing of a business operation to an outsourcing company, and the person continues in employment until the closing date of the sale of assets or outsourcing; (C) the person receives a severance benefit from the ExxonMobil Special Program of Severance Allowances, or similar severance program sponsored by the Corporation or an affiliate; (D) the Plan Administrator determines, in its sole and absolute discretion, that the person is eligible to receive Incentive Pension Benefits. In this regard, the Plan Administrator may from time to time adopt eligibility standards or guidelines that may guide the Plan Administrator’s eligibility determinations, and may in its discretion, modify, suspend, supersede, or cancel such standards or guidelines. 1 2.2 Benefit Formula (A) In General The amount of a person's Incentive Pension Benefit is determined by multiplying 1.6% of the person's final average incentive compensation by the person's years of pensionable service, and dividing the amount so derived by twelve. The result is expressed in the form of a monthly five-year certain and life annuity for the life of the person commencing at the person's age 65 ("Normal Retirement Age"). (B) Pensionable Service For purposes of paragraph (A) above, a person’s “pensionable service” shall be determined as follows: (1) Except as provided in paragraph (2) below, it shall be the amount of pension service credited for the person under the ExxonMobil Pension Plan. (2) In the event a person (a) transfers directly to Exxon Mobil Corporation or one of its U.S. affiliates in connection with an employment localization, (b) upon localization is not credited with pension service under the ExxonMobil Pension Plan for the person’s service with the most recent service- oriented employer, and (c) immediately prior to localization was a participant in the Canadian Supplemental Pension Arrangement (SPA) Bonus (“Imperial Plan”), the person’s pensionable service shall be the sum of the service credited under the Imperial Plan at the time of the person’s localization plus the pension service credited thereafter to the person under the ExxonMobil Pension Plan. (C) Final Average Incentive Compensation For the purposes of paragraph (A) above, a person's "final average incentive compensation" shall be determined in accordance with this paragraph (C). (1) In General A person's final average incentive compensation is the average of the person's three highest annual bonus awards (including awards of zero, if any) under the Corporation's Incentive Programs awarded on any of the five most recent annual award dates immediately preceding the person's termination of employment. (2) Corporate Acquisitions If a person commences employment with the Corporation or one of its affiliates in connection with a corporate acquisition, incentive compensation paid by the person's former employer that is the equivalent of bonus awards payable under the Corporation's Incentive Program may, in the sole discretion of the management of the Corporation, be 2 taken into account for purposes of determining the person’s final average incentive compensation under this Paragraph (C). (3) Annual Bonus Award (a) Items Used in Calculation For purposes of this paragraph (C), in determining the amount of a person's annual bonus award, only awards granted under the short-term incentive part of the Incentive Programs as cash and bonus units are considered. (b) Item Excluded From Calculation For purposes of this paragraph (C), in determining the amount of a person's annual bonus award, an award to a person characterized by the granting authority as a special one-time bonus is disregarded, unless deemed specifically includable by the granting authority at the time of grant. (c) Calculation of Annual Bonus Award If an annual bonus award is granted as bonus units, the maximum settlement value obtainable at the time of the grant shall be used in 2.3 Offset for Similar Benefits calculating the value of the award. If a participant under this Plan is also entitled to payments comparable to the Incentive Pension Benefit for any portion of the same years of pensionable service under a plan of a service-oriented employer, as defined in the ExxonMobil Common Provisions, other than the Corporation, the amount of the Incentive Pension Benefit shall be reduced by the respective amount of such comparable payments. In any given case, the Plan Administrator may determine the precise amount of this offset and if a conversion of currency computation is required, may follow the process established under the ExxonMobil Pension Plan. 2.4 Lapse of Incentive Pension Benefit The portion of any Incentive Pension Benefit deriving from a provisionally granted bonus that is subsequently annulled lapses as of the date of such annulment. 3. Overseas Makeup Benefit 3.1 Eligibility A person is eligible to receive an Overseas Makeup Benefit if the following conditions are met as determined by the Plan Administrator: (A) the person accrues a benefit under a pension plan ("non-U.S. plan") sponsored by a non-U.S. affiliate of the Corporation; (B) the person terminates active participation in the non-U.S. plan and simultaneously becomes a participant in the ExxonMobil Pension Plan or predecessor plan; 3 (C) as a result of terminating active participant status under the non-U.S. plan, the person loses eligibility for all or a portion of the benefit under the non- U.S. plan accrued prior to termination; and (D) the amount of the lost benefit is not provided under the terms of the ExxonMobil Pension Plan, the ExxonMobil Supplemental Pension Plan, or otherwise under this Plan. 3.2 Benefit Formula The amount of the Overseas Makeup Benefit is the amount, expressed as a monthly benefit in the form of a five-year certain and life annuity that is the actuarial equivalent of the lost benefit under the non-U.S. plan. Such amount shall be conclusively determined by the Plan Administrator. 4. Payment of Pension Benefits 4.1 Timing of Payment Payment of a person’s Incentive Pension Benefit and, if applicable, Overseas Makeup Benefit shall occur as soon as practicable following whichever of the pension commencement dates specified in paragraphs (A), (B), (C), or (D) below is applicable to the person. (A) Retirees Except as provided under paragraph (B) or (D) below, in the case of a Retiree, the person’s pension commencement date is the first of the month next following the person’s last day of employment with ExxonMobil. (B) Disability Retirees Except as provided under paragraph (D) below, in the case of a person who retires with eligibility for Disability Benefits under article 6 below prior to the first of the month in which the person attains age 55, the person’s pension commencement date is the first of the month in which the person attains age 55. (C) Terminees Except as provided under paragraph (D) below, in the case of a person who is eligible for an Incentive Pension Benefit under Section 2.1(B), (C), or (D) above, the person’s pension commencement date is the first of the month next following three months from the person’s last day of employment with ExxonMobil. (D) Key Employees Notwithstanding paragraphs (A), (B), or (C) above, in the case of a person who, at the time of his or her termination of employment, has a Classification Level of 35 or above (“Key Employee”), the person’s pension commencement date is the first of the month next following six months from the person’s last day of employment with ExxonMobil. 4 4.2 Reduction for Early Commencement If a person’s pension commencement date under section 4.1 above occurs prior to the month in which the person reaches Normal Retirement Age, the person’s Incentive Pension Benefit and/or Overseas Makeup Benefit is reduced by applying the early commencement factors specified under the ExxonMobil Pension Plan for a benefit commencing at the person's then age. 4.3 Form of Payment Payment of a person's Incentive Pension Benefit or Overseas Makeup Benefit shall be made in a lump sum that is the actuarial equivalent of the five-year certain and life annuity measured as of the person’s pension commencement date specified under section 4.1 above. For this purpose, actuarial equivalence shall be determined by the Plan Administrator using the factors and procedures that are used for the calculation of the lump-sum payment option under the ExxonMobil Pension Plan. 4.4 Adjustment for Key Employees A Key Employee's Incentive Pension Benefit and/or Overseas Makeup Benefit shall not be less than the amount equal to the person’s benefit calculated as of the pension commencement date that would apply if the person were not a Key Employee plus interest from such date until the person’s actual pension commencement date. For this purpose, interest shall be credited at a rate equal to the Citibank prime lending rate in effect on the date the person separates from employment, or, if the person’s last day of employment is on or after November 1, 2022, at the interest rate determined under section 4.4(D)(3)(b)(iii) of Part 1 of the ExxonMobil Pension Plan on the first of the month immediately following the person’s last day of employment, but taking into account only the first segment rate for this purpose. 5.1 In General If a person dies who, at the time of his death, 5. Death Benefit (A) is an active employee with 15 or more years of Benefit Plan Service, as determined under the ExxonMobil Common Provisions, or (B) had retired with eligibility for an Incentive Pension Benefit and/or a Overseas Makeup Benefit and had not received such benefit, a lump-sum death benefit shall be payable to the person's beneficiary (as determined under section 5.2 below). The death benefit payable to the person's beneficiary shall be the lump-sum equivalent value of the amount of the Pension Benefit and Overseas Makeup Benefit to which the person was or would have been entitled. For this purpose, equivalent value shall be determined by the Plan Administrator using the factors and procedures that are used for the calculation of similar benefits under the ExxonMobil Pension Plan. 5 5.2 Designation of Beneficiaries (A) In General A person may name one or more designated beneficiaries to receive payment of the death benefits payable under section 5.1 above in the event of the person's death. Beneficiary designations shall be made in accordance with such procedures as the Plan Administrator may establish. Spousal consent to any such designation is not required. (B) Default Beneficiaries (1) In General If no specific designation is in effect, the deceased's beneficiary is the person or persons in the first of the following classes of successive beneficiaries living at the time of death of the deceased: (a) spouse; (b) children who survive the deceased or who die before the deceased leaving children of their own who survive the deceased; (c) parents; (d) brothers and sisters who survive the deceased or who die before the deceased leaving children of their own who survive the deceased. If there are no members of any class of such beneficiaries, payment is made to the deceased's executors or administrators. (2) Allocation Among Default Beneficiaries If the same class of beneficiaries under paragraph (1) above contains two or more persons, they share equally, with further subdivision of such equal shares as next provided. In class (b), where a child dies before the deceased leaving children who survive the deceased, such child's share is subdivided equally among those children. In class (d), where a brother or sister dies before the deceased leaving children who survive the deceased, such brother or sister's share is subdivided equally among those children. (3) Definitions For purposes of this section 5.2, "child" means a person's son or daughter by legitimate blood relationship or legal adoption; "parent" means a person's father or mother by legitimate blood relationship or legal adoption; "brother" or "sister" means another child of either or both of one's parents. 6 6. Disability Benefit 6.1 Nature of Disability Benefits The benefits provided under this article 6 ("Disability Benefits") are in the nature of long-term disability benefits, payable on account of and for the duration of a person's incapacity on account of disability. These Disability Benefits are intended to qualify as employee welfare benefits under ERISA and as "disability pay" under section 409A of the Internal Revenue Code and its supporting regulations, thereby being exempt from the scope and application of section 409A. 6.2 Payment of Disability Benefit If a person who becomes a Retiree also becomes entitled to long-term disability benefits under the ExxonMobil Disability Plan, the person shall receive monthly Disability Benefits under this Plan. Such Disability Benefits shall commence at the time the person commences long-term disability benefits under the ExxonMobil Disability Plan and shall continue as long as entitlement to long-term disability or transition benefits under such plan continues. 6.3 Benefit Formula (A) In General The amount of each monthly Disability Benefit payable to a person is determined by dividing one-half of the person's final average incentive compensation, determined under section 2.2(C) above, by 12 and deducting therefrom the offset described in paragraph (B) below. (B) Offset Commencing with the month in which a person's Incentive Pension Benefit is paid, the amount of the person's monthly Disability Benefit shall be reduced by the monthly amount of the person's Incentive Pension Benefit and/or Overseas Makeup Benefit (expressed as a five-year-certain and life annuity). In the case of a Key Employee, the offset provided under this paragraph (B) shall be applied beginning with the month his or her Incentive Pension Benefit would have been paid if he or she were not a Key Employee. 6.4 Offset for Similar Benefit If a person receiving Disability Benefits hereunder is also entitled to comparable payments under a plan of a service-oriented employer (as defined in the ExxonMobil Common Provisions) other than the Corporation under circumstances where the Plan Administrator determines that such benefits are duplicative of the Disability Benefits payable hereunder, then such Disability Benefits shall be reduced by the amount of such comparable payment. In any given case, the Plan Administrator may determine the precise amount of this offset and if a conversion of currency computation is required, may follow the process established under the ExxonMobil Pension Plan. 7 6.5 Disability Death Benefit (A) Death During Employment If a person dies as an active employee with 15 or more years of Benefit Plan Service, as determined under the ExxonMobil Common Provisions, then the person's beneficiary (as determined under section 5.2 above) shall receive a disability death benefit equal to the present value of 60 monthly installments of the person's Disability Benefit, calculated as if the person had become eligible for Disability Benefit payments on the day prior to death. For purposes of this paragraph (A), the value of the person's Disability Benefit installments shall be determined by applying the offset under section 6.3(B) above as if the person's Incentive Pension Benefit and/or Overseas Makeup Benefit were payable at the time of death. (B) Death After Commencement of Disability Retirement Payments If a person dies while receiving Disability Benefits under this article 6 but before the receipt of 60 monthly installments, the person's beneficiary (as determined under section 5.2 above) shall receive the lump-sum equivalent value of the remaining 60 monthly installments. If at the time of death the person's Incentive Pension Benefit had not been paid, then the value of the person's remaining Disability Benefit installments shall be determined by applying the offset under section 6.3(B) above as if the person's Incentive Pension Benefit and/or Overseas Makeup Benefit were paid at the time of death. 7. Miscellaneous 7.1 Plan Administrator The Plan Administrator shall be the Manager, Compensation, Benefit Plans and Policies, Human Resources Department, Exxon Mobil Corporation. The Plan Administrator shall have the right and authority to conclusively interpret this Plan for all purposes, including the determination of any person's eligibility for benefits hereunder and the resolution of any and all appeals relating to claims by participants or beneficiaries, with any such interpretation being conclusive for all participants and beneficiaries. 7.2 Nature of Payments Payments provided under this Plan are considered general obligations of the Corporation. 7.3 Assignment or Alienation Except as provided in section 7.5 below, payments provided under this Plan may not be assigned or otherwise alienated or pledged. 7.4 Amendment or Termination The Corporation reserves the right to amend or terminate this Plan, in whole or in part, including the right at any time to reduce or eliminate any accrued benefits hereunder and to alter or amend the benefit formula set out herein. 8 7.5 Forfeiture of Benefits Any payments received under this Plan shall be forfeited and returned if the forfeiture and repayment of such payments is required by any clawback policy adopted by the Corporation. Additionally, no person shall be entitled to receive payments under this Plan, and any payments received under this Plan shall be forfeited and returned, if it is determined by the Corporation in its sole discretion, acting through its chief executive or such person or committee as the chief executive may designate, that a person otherwise entitled to a payment under this Plan or who has commenced receiving payments under this Plan: (A) engaged in gross misconduct harmful to the Corporation, (B) committed a criminal violation harmful to the Corporation, (C) had concealed actions described in (A) or (B) above which would have brought about termination from employment thereby making the person ineligible for benefits under this Plan, (D) separated from service prior to attaining Normal Retirement Age without having received from the Corporation or its delegate prior written approval for such termination, given in the sole discretion of the Corporation or its delegatee and in the context of recognition that benefits under this Plan would not be forfeited upon such termination, or (E) had been terminated for cause. 9 Exxon Mobil Corporation 22777 Springwoods Village Parkway Spring, TX 77389 EXHIBIT 10(iii)(f.3) Craig S. Morford Vice President, General Counsel & Secretary Law Department January 2, 2024 [Name of Non-Employee Director] I am pleased to inform you that on January 2, 2024, you were granted 2,500 shares of restricted stock under Exxon Mobil Corporation's 2004 Non-Employee Director Restricted Stock Plan (the "Plan") and in accordance with the Board's standing resolution regarding grants under the Plan. This letter summarizes key terms of your award and is qualified by reference to the Plan. You should refer to the text of the Plan for a detailed description of the terms and conditions of your award. Copies of the Plan have been previously distributed to you and are also available on request to me at any time. The restricted stock has been registered in your name and will be held in book-entry form by the Corporation's agent during the restricted period. As the owner of record, you have the right to vote the shares and receive cash dividends. However, during the restricted period the shares may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and your restricted stock account will be subject to stop transfer instructions. When the restricted period expires, shares will be delivered to or for your account free of restrictions. The restricted period for this award began at the time of grant. The restricted period will expire on the earliest of grantee leaving the Board after reaching retirement age (currently age 75), leaving the Board in good standing (as determined by the Board) before reaching retirement age, or by reason of death. By accepting this award, you agree to all its terms and conditions, including the restrictions on transfer and events of forfeiture. You are entitled to designate a beneficiary for your restricted stock account. Please contact Micki Sage at (346) 502-7352 for the necessary form should you wish to do so. Additional information concerning your award, including information on the tax consequences of your award and certain additional information required by the Securities Act of 1933, is also enclosed with this letter. Should you have any questions concerning the Plan or this award, please feel free to contact me at (346) 502-7595. Sincerely, [signed by Craig S. Morford] Enclosures Subsidiaries of the Registrant (1), (2) and (3) – at December 31, 2023 AKG Marketing Company Limited Al-Jubail Petrochemical Company (4) (5) Alberta Products Pipe Line Ltd. (5) Ancon Insurance Company Inc. Barzan Gas Company Limited (5) BEB Erdgas und Erdoel GmbH & Co. KG (4) (5) Canada Imperial Oil Limited Caspian Pipeline Consortium (5) Coral FLNG S.A. (5) Cross Timbers Energy LLC (4) (5) Denbury Green Pipeline-Texas, LLC Denbury Gulf Coast Pipelines, LLC Denbury Onshore, LLC Ellora Energy Inc. Esso Australia Resources Pty Ltd Esso Deutschland GmbH Esso Erdgas Beteiligungsgesellschaft mbH Esso Exploration and Production Angola (Overseas) Limited Esso Exploration and Production Nigeria (Deepwater) Limited Esso Exploration and Production Nigeria Limited Esso Exploration and Production UK Limited Esso Exploration Angola (Block 15) Limited Esso Exploration Angola (Block 17) Limited Esso Italiana S.r.l. Esso Nederland B.V. Esso Norge AS Esso Petroleum Company Limited Esso Societe Anonyme Francaise Exxon Azerbaijan Limited Exxon Chemical Arabia Inc. Exxon Neftegas Limited ExxonMobil (China) Investment Co. Ltd. ExxonMobil (Huizhou) Chemical Co. Ltd. ExxonMobil (Taicang) Petroleum Co. Ltd. ExxonMobil Abu Dhabi Offshore Petroleum Company Limited ExxonMobil Africa and Middle East Management Ltd ExxonMobil Alaska Production Inc. ExxonMobil Asia Pacific Pte. Ltd. ExxonMobil Australia Pty Ltd ExxonMobil Barzan Limited ExxonMobil Canada Ltd. 1 EXHIBIT 21 State or Country of Organization Bahamas Saudi Arabia Canada Vermont Qatar Germany Canada Russia/Kazakhstan Mozambique Delaware Delaware Delaware Delaware Delaware Australia Germany Germany Bahamas Nigeria Nigeria United Kingdom Bahamas Bahamas Italy Netherlands Norway United Kingdom France Bahamas Delaware Bahamas China China China Bahamas United Arab Emirates Delaware Singapore Australia Bahamas Canada Percentage of Voting Securities Owned Directly or Indirectly by Registrant 87.5 50 45 100 7 50 69.6 7.50 25 50 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 82.89 100 100 100 100 100 100 100 100 100 100 100 100 100 ExxonMobil Canada Properties ExxonMobil Capital International B.V. ExxonMobil Central Europe Holding GmbH ExxonMobil Chemical France ExxonMobil Chemical Gulf Coast Investments LLC ExxonMobil China Petroleum & Petrochemical Company Private Limited ExxonMobil Development Africa B.V. ExxonMobil Egypt (S.A.E.) ExxonMobil Exploracao Brasil Ltda ExxonMobil Exploration and Production Malaysia Inc. ExxonMobil Exploration and Production Tanzania Limited ExxonMobil Exploration Argentina Sociedad de Responsabilidad Limitada ExxonMobil Finance Company Limited ExxonMobil Financial Investment Company Limited ExxonMobil Financial Services B.V. ExxonMobil Gas Marketing Europe Limited ExxonMobil Global Services Company ExxonMobil Guyana Ltd. ExxonMobil Holding Company Holland LLC ExxonMobil Italiana Gas S.r.l. ExxonMobil Kazakhstan Inc. ExxonMobil Kazakhstan Ventures Inc. ExxonMobil Marine Limited ExxonMobil Mexico S.A. de C.V. ExxonMobil Oil Corporation ExxonMobil Permian Highway Pipeline LLC ExxonMobil Petroleum & Chemical BV ExxonMobil Pipeline Company LLC ExxonMobil PNG Antelope Limited ExxonMobil PNG Limited ExxonMobil Qatargas (II) Limited ExxonMobil Qatargas Inc. ExxonMobil Ras Laffan (III) Limited ExxonMobil Rasgas Inc. ExxonMobil Sales and Supply LLC ExxonMobil Technology and Engineering Company ExxonMobil Upstream Integrated Solutions Company ExxonMobil Ventures Cyprus Limited Fujian Refining & Petrochemical Co. Ltd. (5) GasTerra B.V. (5) Golden Pass LNG Terminal Investments LLC Golden Pass LNG Terminal LLC (5) Golden Pass Pipeline LLC (5) 2 Percentage of Voting Securities Owned Directly or Indirectly by Registrant State or Country of Organization 100 100 100 100 100 100 100 100 100 100 100 70 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 25 25 100 30 30 Canada Netherlands Germany France Delaware Singapore Netherlands Egypt Brazil Delaware Bahamas Argentina United Kingdom United Kingdom Netherlands United Kingdom Delaware Bahamas Delaware Italy Bahamas Delaware United Kingdom Mexico New York Delaware Belgium Delaware Papua New Guinea Papua New Guinea Bahamas Delaware Bahamas Delaware Delaware Delaware Delaware Cyprus China Netherlands Delaware Delaware Delaware Gulf Coast Growth Ventures LLC (4) (5) Imperial Oil Limited Imperial Oil Resources Limited Imperial Oil Resources N.W.T. Limited Imperial Oil/Petroliere Imperiale Infineum USA L.P. (4) (5) Marine Well Containment Company LLC (5) Mobil Australia Resources Company Pty Limited Mobil Equatorial Guinea Inc. Mobil Oil Australia Pty Ltd Mobil Oil Exploration & Producing Southeast Inc. Mobil Oil New Zealand Limited Mobil Producing Nigeria Unlimited Mobil Yanbu Petrochemical Company Inc. Mobil Yanbu Refining Company Inc. Mozambique Rovuma Venture S.p.A. (5) Nederlandse Aardolie Maatschappij B.V. (4) (5) Palmetto Transoceanic LLC Papua New Guinea Liquefied Natural Gas Global Company LDC (5) Permian Express Partners LLC (5) Permian Highway Pipeline LLC (5) Phillips Exploration LLC PT ExxonMobil Lubricants Indonesia QatarEnergy LNG N (2) (5) QatarEnergy LNG NFE (3) (5) QatarEnergy LNG S (1) (5) QatarEnergy LNG S (2) (5) QatarEnergy LNG S (3) (5) Saudi Aramco Mobil Refinery Company Ltd. (4) (5) Saudi Yanbu Petrochemical Co. (4) (5) SeaRiver Maritime Inc. SeaRiver Maritime LLC South Hook LNG Terminal Company Limited (5) Tengizchevroil LLP (5) Terminale GNL Adriatico S.r.l. (5) Wink to Webster Pipeline LLC WOREX XH LLC XTO Delaware Basin LLC XTO Energy Inc. XTO Holdings LLC XTO Permian Midstream LLC XTO Permian Operating LLC 3 Percentage of Voting Securities Owned Directly or Indirectly by Registrant State or Country of Organization 50 69.6 69.6 69.6 69.6 50 10 100 100 100 100 100 100 100 100 35.714 50 100 33.2 12.3 17 100 100 24.15 25 24.999 30.517 30 50 50 100 100 24.15 25 70.678 45 82.89 100 100 100 100 100 100 Delaware Canada Canada Canada Canada Delaware Delaware Australia Delaware Australia Delaware New Zealand Nigeria Delaware Delaware Italy Netherlands Delaware Bahamas Delaware Delaware Delaware Indonesia Qatar Qatar Qatar Qatar Qatar Saudi Arabia Saudi Arabia Delaware Delaware United Kingdom Kazakhstan Italy Delaware France Delaware Texas Delaware Delaware Delaware Texas NOTES: (1) For the purposes of this list, if the registrant owns directly or indirectly approximately 50 percent of the voting securities of any person and approximately 50 percent of the voting securities of such person is owned directly or indirectly by another interest, or if the registrant includes its share of net income of any other unconsolidated person in consolidated net income, such person is deemed to be a subsidiary. (2) With respect to certain companies, shares in names of nominees and qualifying shares in names of directors are included in the above percentages. (3) The names of other subsidiaries have been omitted from the above list since considered in the aggregate, they would not constitute a significant subsidiary under Securities and Exchange Commission Regulation S-X, Rule 1-02(w). (4) The registrant owns directly or indirectly approximately 50 percent of the securities of this person and approximately 50 percent of the voting securities of this person is owned directly or indirectly by another single interest. (5) The investment in this unconsolidated person is represented by the registrant's percentage interest in the underlying net assets of such person. The accounting for these unconsolidated persons is referred to as the equity method of accounting. 4 EXHIBIT 23 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-270460), Form S-8 (Nos. 333-145188, 333-110494, 333-183012, 333-264665 and 333-117980), and Form S-4 (No. 333-275695) of Exxon Mobil Corporation of our report dated February 28, 2024 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP Houston, Texas February 28, 2024 Exxon Mobil Corporation Rule 10D-1 Recoupment Policy Effective December 1, 2023 1. Purpose. This policy is adopted by Exxon Mobil Corporation (the “Corporation”) to comply with Listing Standard 303A.14 adopted by the New York Stock Exchange (“NYSE”) to implement Rule 10D-1 under the Securities Exchange Act of 1934, as amended (“Rule 10D-1”). This policy is in addition to, not in lieu of, any other remedies or rights of compensation forfeiture or recoupment that may be available to the Corporation under any other policy, plan or award terms, and any other available legal remedies (including remedies the Corporation may have against any persons whose misconduct caused or contributed to a Financial Restatement), provided the Corporation will not recover amounts under such other remedies or rights to the extent such amounts are recovered under this policy (and vice versa). 2. Statement of Rule 10D-1 Policy. If the Corporation is required to prepare a Financial Restatement (as described in the definition of Recovery Trigger Date), the Corporation will, subject to the terms of this policy and Rule 10D-1, recover reasonably promptly the amount of any Covered Compensation Received by a Covered Executive during the Recovery Period that exceeds the amount of Covered Compensation that otherwise would have been Received had it been determined based on the Financial Restatement, without regard to any taxes paid (such excess amount, “Recoverable Compensation”). Except as otherwise defined in this policy, applicable terms have the meanings provided below in Section 9. 3. Estimation of Stock Price Effect. For Covered Compensation based on stock price or total shareholder return where the amount of Recoverable Compensation is not subject to mathematical recalculation directly from the information in a Financial Restatement, the Committee will determine such amount of Recoverable Compensation based on a reasonable estimate of the effect of the Financial Restatement on the Corporation’s stock price or total shareholder return. The Corporation will maintain and make available to the NYSE documentation of such reasonable estimate. 4. Exceptions. The Corporation will not be required to recover any Recoverable Compensation to the extent the Committee determines such recovery would be impracticable and either of the following conditions is satisfied: (i) after having made reasonable attempt(s) to make such recovery, the Committee determines the direct expense paid to a third party to assist in enforcing such recovery would exceed the amount to be recovered; provided, that before the Committee concludes recovery would be impracticable due to expense of enforcement, the Corporation shall have documented such reasonable recovery attempt(s), and provided that documentation to the NYSE; or (ii) recovery of such Recoverable Compensation would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Corporation, to fail to meet the requirements of Section 401(a)(13) or 411(a) of the U.S. Internal Revenue Code of 1986, as amended, and regulations thereunder. 5. Manner of Recovery. The Corporation may effect any recoupment of Recoverable Compensation under this policy in any manner permitted by applicable law, including, without limitation, by requiring payment of amount(s) to the Corporation, by set-off, by cancellation of outstanding unvested or deferred compensation, by reducing future compensation, or by such other means or combination of means as the Committee in its sole discretion determines to be appropriate. 6. No Reimbursement of Indemnification. The Corporation will not pay or reimburse the cost of insurance for, or indemnify any Covered Executive against, the loss of Recoverable Compensation pursuant to this policy. 7. Administration. This policy will be administered by the Compensation Committee (the “Committee”) of the Corporation’s Board of Directors and will be interpreted and administered consistently with Rule 10D-1. Any determinations made by the Committee under this policy are final and binding on all affected individuals. 8. Amendment. The Board of Directors of the Corporation may amend or modify this policy at any time and from time to time, consistently with its purpose as stated in Section 1 and Rule 10D-1 as then in effect. 9. Definitions. For purposes of this policy: “Covered Compensation” means any Incentive-Based Compensation Received by a Covered Executive during the applicable Recovery Period, provided such Covered Compensation was Received by a person (i) on or after October 2, 2023, (ii) after the person began service as an Executive Officer, and (iii) who served as an Executive Officer at any time during the performance period for the applicable Incentive-Based Compensation. “Covered Executive” means any current or former Executive Officer. “Executive Officer” means any “officer” of the Corporation for purposes of Section 16(a) of the U.S. Securities Exchange Act of 1934, as determined by the Board of Directors of the Corporation. “Financial Reporting Measure” means any (i) measure that is determined and presented in accordance with the accounting principles used in preparing the Corporation’s financial statements, (ii) stock price measure, or (iii) total shareholder return measure; and (iv) any measures derived in whole or in part from any measure referenced in the preceding clauses (i), (ii), or (iii). Such measure does not need to be presented within the Corporation’s financial statements or included in a filing with the U.S. Securities and Exchange Commission to constitute a Financial Reporting Measure. “Financial Restatement” means a restatement of the Corporation’s financial statements due to the Corporation’s material non-compliance with any financial reporting requirement under the U.S. federal securities laws that is required in order to correct (i) an error in previously issued financial statements that is material to the previously issued financial statements, or (ii) an error that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period. “Incentive-Based Compensation” means any compensation granted, earned, or vested based in whole or in part on the Corporation’s attainment of a Financial Reporting Measure. For purposes of this policy, “Incentive-Based Compensation” also includes any amounts based on or calculated by reference to Incentive-Based Compensation, including, if applicable, amounts under any long-term disability, life insurance, supplemental retirement plan, or notional account based on Incentive-Based Compensation, as well as any earnings accrued on such amounts. Incentive-Based Compensation is deemed to be “Received” in the fiscal period during which the relevant Financial Reporting Measure is attained, even if the payment or grant of such Incentive-Based Compensation occurs later. “Recovery Period” means the three completed fiscal years immediately preceding any applicable Recovery Trigger Date, and any transition period of less than nine (9) months resulting from a change in the Corporation’s fiscal year within or immediately following those three completed fiscal years. “Recovery Trigger Date” means the earlier of (i) the date the Board of Directors of the Corporation (or a committee thereof, or the officer(s) of the Corporation authorized to take such action if Board action is not required) concludes, or reasonably should have concluded, that the Corporation is required to prepare a Financial Restatement, and (ii) the date on which a court, regulator or other legally authorized body directs the Corporation to prepare a Financial Restatement. Certification by Darren W. Woods Pursuant to Securities Exchange Act Rule 13a-14(a) I, Darren W. Woods, certify that: 1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation; EXHIBIT 31.1 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 28, 2024 /s/ DARREN W. WOODS Darren W. Woods Chief Executive Officer Certification by Kathryn A. Mikells Pursuant to Securities Exchange Act Rule 13a-14(a) I, Kathryn A. Mikells, certify that: 1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation; EXHIBIT 31.2 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 28, 2024 /s/ KATHRYN A. MIKELLS Kathryn A. Mikells Senior Vice President and Chief Financial Officer Certification by Len M. Fox Pursuant to Securities Exchange Act Rule 13a-14(a) I, Len M. Fox, certify that: 1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation; EXHIBIT 31.3 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 28, 2024 /s/ LEN M. FOX Len M. Fox Vice President and Controller (Principal Accounting Officer) Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350 For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Darren W. Woods, the chief executive officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge: (i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. EXHIBIT 32.1 Date: February 28, 2024 A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request. /s/ DARREN W. WOODS Darren W. Woods Chief Executive Officer Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350 EXHIBIT 32.2 For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Kathryn A. Mikells, the chief financial officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to her knowledge: (i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 28, 2024 /s/ KATHRYN A. MIKELLS Kathryn A. Mikells Senior Vice President and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request. Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350 For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Len M. Fox, the principal accounting officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge: (i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. EXHIBIT 32.3 Date: February 28, 2024 A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request. /s/ LEN M. FOX Len M. Fox Vice President and Controller (Principal Accounting Officer) 

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