xom-20231231


			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

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-2256

Exxon Mobil Corporation

(Exact name of registrant as specified in its charter)


New Jersey						13-5409005
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification Number)

22777 Springwoods Village Parkway, Spring, Texas 77389-1425

(Address of principal executive offices) (Zip Code)

(972) 940-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

Common Stock, without par value

XOM

New York Stock Exchange

0.142% Notes due 2024

XOM24B

New York Stock Exchange

0.524% Notes due 2028

XOM28

New York Stock Exchange

0.835% Notes due 2032

XOM32

New York Stock Exchange

1.408% Notes due 2039

XOM39A

New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 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						Outstanding as of January 31, 2024
Common stock, without par value						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	1
Item 1A.	Risk Factors	2
Item 1B.	Unresolved Staff Comments	7
Item 1C.	Cybersecurity	8
Item 2.	Properties	9
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28
Information about our Executive Officers		29

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	32
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	32

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	32
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	33
Item 13.	Certain Relationships and Related Transactions, and Director Independence	33
Item 14.	Principal Accounting Fees and Services	33

PART IV

Item 15.	Exhibit and Financial Statement Schedules	33
Item 16.	Form 10-K Summary	33

Financial Section		34
Index to Exhibits		134
Signatures		135
Exhibits 31 and 32 — Certifications

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.

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.

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.

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.

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.

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.

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.

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.

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
United States	1,208	527	—	—	8,138	3,091
Canada/Other Americas (1)	433	—	2,307	242	329	3,037
Europe	4	—	—	—	307	55
Africa	204	13	—	—	220	254
Asia	1,948	48	—	—	1,935	2,318
Australia/Oceania	35	10	—	—	3,163	572
Total Consolidated	3,832	598	2,307	242	14,092	9,327

Equity Companies
United States	7	4	—	—	57	21
Europe	3	—	—	—	290	51
Africa	5	—	—	—	780	135
Asia	329	109	—	—	4,223	1,142
Total Equity Company	344	113	—	—	5,350	1,349
Total Developed	4,176	711	2,307	242	19,442	10,676

Undeveloped
Consolidated Subsidiaries
United States	894	604	—	—	4,125	2,186
Canada/Other Americas (1)	561	—	107	112	191	812
Europe	—	—	—	—	—	—
Africa	20	—	—	—	—	20
Asia	719	32	—	—	859	894
Australia/Oceania	26	2	—	—	2,695	477
Total Consolidated	2,220	638	107	112	7,870	4,389

Equity Companies
United States	—	—	—	—	—	—
Europe	—	—	—	—	54	9
Africa	—	—	—	—	—	—
Asia	451	220	—	—	7,098	1,854
Total Equity Company	451	220	—	—	7,152	1,863
Total Undeveloped	2,671	858	107	112	15,022	6,252

Total Proved Reserves	6,847	1,569	2,414	354	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.

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.

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.

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)	2023		2022		2021
	Crude Oil	NGL	Crude Oil	NGL	Crude Oil	NGL
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States	556	238	523	211	482	195
Canada/Other Americas (1)	240	2	196	2	130	3
Europe	2	—	2	—	16	3
Africa	216	4	233	5	241	7
Asia	417	28	407	23	407	21
Australia/Oceania	24	12	27	16	28	15
Total Consolidated Subsidiaries	1,455	284	1,388	257	1,304	244

Equity Companies
United States	8	1	41	1	43	1
Europe	2	—	2	—	3	—
Africa	1	—	—	—	—	—
Asia	216	60	216	59	207	60
Total Equity Companies	227	61	259	60	253	61
Total crude oil and natural gas liquids production	1,682	345	1,647	317	1,557	305

Bitumen production
Consolidated Subsidiaries
Canada/Other Americas	355		327		365

Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas	67		63		62

Total liquids production	2,449		2,354		2,289

(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States	2,292		2,531		2,724
Canada/Other Americas (1)	96		148		195
Europe	266		306		377
Africa	35		64		43
Asia	915		779		807
Australia/Oceania	1,298		1,440		1,280
Total Consolidated Subsidiaries	4,902		5,268		5,426

Equity Companies
United States	19		20		22
Europe	148		361		431
Africa	90		7		—
Asia	2,575		2,639		2,658
Total Equity Companies	2,832		3,027		3,111
Total natural gas production available for sale	7,734		8,295		8,537

(thousands of oil-equivalent barrels daily)
Oil-equivalent production	3,738		3,737		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.

B. Production Prices and Production Costs

The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.


(dollars per unit)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total
2023
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel	75.45	80.51	71.99	82.70	79.50	70.26	78.43
NGL, per barrel	23.88	24.44	64.10	44.72	29.81	34.35	25.12
Natural gas, per thousand cubic feet	1.16	2.57	13.64	2.04	2.40	9.31	4.26
Bitumen, per barrel	—	49.64	—	—	—	—	49.64
Synthetic oil, per barrel	—	77.56	—	—	—	—	77.56
Average production costs, per oil-equivalent barrel - total	9.70	19.94	36.37	20.70	5.26	5.55	12.05
Average production costs, per barrel - bitumen	—	23.80	—	—	—	—	23.80
Average production costs, per barrel - synthetic oil	—	45.91	—	—	—	—	45.91

Equity Companies
Average production prices
Crude oil, per barrel	75.48	—	77.82	71.92	74.59	—	74.63
NGL, per barrel	19.13	—	—	—	45.64	—	45.19
Natural gas, per thousand cubic feet	5.25	—	22.22	5.89	8.54	—	9.15
Average production costs, per oil-equivalent barrel - total	53.49	—	43.99	6.74	2.77	—	5.09

Total
Average production prices
Crude oil, per barrel	75.45	80.51	74.13	82.66	77.83	70.26	77.92
NGL, per barrel	23.86	24.44	64.10	44.72	40.59	34.35	28.66
Natural gas, per thousand cubic feet	1.19	2.57	16.71	4.81	6.93	9.31	6.05
Bitumen, per barrel	—	49.64	—	—	—	—	49.64
Synthetic oil, per barrel	—	77.56	—	—	—	—	77.56
Average production costs, per oil-equivalent barrel - total	10.15	19.94	39.09	19.79	3.91	5.55	10.63
Average production costs, per barrel - bitumen	—	23.80	—	—	—	—	23.80
Average production costs, per barrel - synthetic oil	—	45.91	—	—	—	—	45.91

2022
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel	93.60	97.05	91.32	103.45	94.94	94.43	96.16
NGL, per barrel	38.54	45.22	71.43	57.83	35.77	46.91	39.37
Natural gas, per thousand cubic feet	5.37	4.40	21.17	2.57	2.60	11.47	7.48
Bitumen, per barrel	—	64.12	—	—	—	—	64.12
Synthetic oil, per barrel	—	96.08	—	—	—	—	96.08
Average production costs, per oil-equivalent barrel - total	9.40	24.63	23.77	21.68	7.31	4.97	13.09
Average production costs, per barrel - bitumen	—	29.90	—	—	—	—	29.90
Average production costs, per barrel - synthetic oil	—	51.52	—	—	—	—	51.52

Equity Companies
Average production prices
Crude oil, per barrel	94.58	—	90.91	60.00	94.32	—	94.32
NGL, per barrel	39.53	—	—	—	59.52	—	59.05
Natural gas, per thousand cubic feet	5.49	—	21.10	2.72	13.08	—	13.97
Average production costs, per oil-equivalent barrel - total	40.42	—	26.86	42.24	1.45	—	5.57

Total
Average production prices
Crude oil, per barrel	93.67	97.05	91.15	103.42	94.73	94.43	95.88
NGL, per barrel	38.55	45.22	71.43	57.83	52.85	46.91	43.09
Natural gas, per thousand cubic feet	5.37	4.40	21.14	2.59	10.70	11.47	9.85
Bitumen, per barrel	—	64.12	—	—	—	—	64.12
Synthetic oil, per barrel	—	96.08	—	—	—	—	96.08
Average production costs, per oil-equivalent barrel - total	10.57	24.63	25.43	21.79	4.02	4.97	11.43
Average production costs, per barrel - bitumen	—	29.90	—	—	—	—	29.90
Average production costs, per barrel - synthetic oil	—	51.52	—	—	—	—	51.52


(dollars per unit)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total
2021
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel	65.03	68.56	66.20	70.21	67.28	69.00	67.14
NGL, per barrel	32.24	30.51	42.31	54.57	32.62	43.07	33.65
Natural gas, per thousand cubic feet	3.02	2.92	11.83	1.67	2.11	6.64	4.33
Bitumen, per barrel	—	44.26	—	—	—	—	44.26
Synthetic oil, per barrel	—	64.73	—	—	—	—	64.73
Average production costs, per oil-equivalent barrel - total	8.33	22.47	25.31	18.92	7.16	5.14	12.15
Average production costs, per barrel - bitumen	—	22.69	—	—	—	—	22.69
Average production costs, per barrel - synthetic oil	—	48.87	—	—	—	—	48.87

Equity Companies
Average production prices
Crude oil, per barrel	67.06	—	62.60	—	65.85	—	66.01
NGL, per barrel	29.94	—	—	—	52.14	—	51.64
Natural gas, per thousand cubic feet	3.11	—	8.19	—	6.54	—	6.74
Average production costs, per oil-equivalent barrel - total	30.51	—	38.82	—	1.59	—	6.67

Total
Average production prices
Crude oil, per barrel	65.20	68.56	65.54	70.21	66.80	69.00	66.96
NGL, per barrel	32.23	30.51	42.31	54.57	47.10	43.07	37.27
Natural gas, per thousand cubic feet	3.02	2.92	9.89	1.67	5.50	6.64	5.21
Bitumen, per barrel	—	44.26	—	—	—	—	44.26
Synthetic oil, per barrel	—	64.73	—	—	—	—	64.73
Average production costs, per oil-equivalent barrel - total	9.24	22.47	31.79	19.04	4.06	5.14	10.92
Average production costs, per barrel - bitumen	—	22.69	—	—	—	—	22.69
Average production costs, per barrel - synthetic oil	—	48.87	—	—	—	—	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.

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	—	1	1
Canada/Other Americas	1	3	5
Europe	1	—	—
Africa	—	—	—
Asia	—	—	—
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	2	4	6

Equity Companies
United States	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Total Equity Companies	—	—	—
Total productive exploratory wells drilled	2	4	6

Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States	1	—	1
Canada/Other Americas	3	4	3
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	4	4	4

Equity Companies
United States	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Total Equity Companies	—	—	—
Total dry exploratory wells drilled	4	4	4


	2023	2022	2021

Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States	446	473	433
Canada/Other Americas	47	33	28
Europe	1	—	1
Africa	4	3	1
Asia	5	5	4
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	503	514	467

Equity Companies
United States	2	49	13
Europe	—	—	1
Africa	—	—	1
Asia	6	10	5
Total Equity Companies	8	59	20
Total productive development wells drilled	511	573	487

Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States	—	—	4
Canada/Other Americas	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	—	—	4

Equity Companies
United States	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Total Equity Companies	—	—	—
Total dry development wells drilled	—	—	4

Total number of net wells drilled	517	581	501

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	Year-End 2023		Year-End 2022
	Gross	Net	Gross	Net

Consolidated Subsidiaries
United States	582	409	804	472
Canada/Other Americas	42	29	54	40
Europe	3	1	2	1
Africa	4	1	10	2
Asia	25	5	18	5
Australia/Oceania	3	1	1	—
Total Consolidated Subsidiaries	659	446	889	520

Equity Companies
United States	9	—	13	2
Europe	—	—	—	—
Africa	—	—	—	—
Asia	61	4	8	3
Total Equity Companies	70	4	21	5
Total gross and net wells drilling	729	450	910	525

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.

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.

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.

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	21,193	9,503	8,210	4,801	19,006	7,576	11,495	7,516
Canada/Other Americas	4,193	4,131	2,901	1,034	4,394	4,310	2,903	1,033
Europe	476	125	396	198	536	127	433	205
Africa	605	204	21	8	590	191	24	10
Asia	995	293	148	85	999	318	147	86
Australia/Oceania	449	84	98	40	473	89	92	38
Total Consolidated Subsidiaries	27,911	14,340	11,774	6,166	25,998	12,611	15,094	8,888

Equity Companies
United States	2,634	340	3,322	329	12,068	4,777	3,341	331
Europe	57	20	454	139	57	20	482	150
Africa	—	—	6	2	—	—	6	2
Asia	234	58	145	33	233	58	145	33
Total Equity Companies	2,925	418	3,927	503	12,358	4,855	3,974	516
Total gross and net productive wells	30,836	14,758	15,701	6,669	38,356	17,466	19,068	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.

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	10,354	6,566	11,022	6,681
Canada/Other Americas (1)	2,145	1,526	2,113	1,509
Europe	983	560	1,238	580
Africa	2,109	704	2,186	736
Asia	1,582	451	1,582	462
Australia/Oceania	3,174	1,033	3,242	1,067
Total Consolidated Subsidiaries	20,347	10,840	21,383	11,035

Equity Companies
United States	583	113	702	166
Europe	3,590	1,109	3,646	1,117
Africa	178	44	178	44
Asia	665	157	665	157
Total Equity Companies	5,016	1,423	5,191	1,484
Total gross and net developed acreage	25,363	12,263	26,574	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
United States	6,738	2,602	6,455	2,587
Canada/Other Americas (1)	30,773	15,012	32,441	15,838
Europe	12,489	8,173	12,592	8,231
Africa	18,309	12,696	20,620	13,113
Asia	766	227	766	227
Australia/Oceania	4,811	2,309	4,811	2,309
Total Consolidated Subsidiaries	73,886	41,019	77,685	42,305

Equity Companies
United States	—	—	150	61
Europe	381	110	482	131
Africa	418	104	418	104
Asia	298	19	296	19
Total Equity Companies	1,097	233	1,346	315
Total gross and net undeveloped acreage	74,983	41,252	79,031	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.

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.

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.

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.

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)

					ExxonMobil Interest %	ExxonMobil’s Share of Refining Capacity (2)	Ethylene	Polyethylene	Polypropylene
						(thousands of barrels daily)	(millions of metric tons per year)
United States
Joliet	Illinois	■			100	258	—	—	—
Baton Rouge	Louisiana	■	▲	●	100	523	1.1	1.3	0.9
Baytown	Texas	■	▲	●	100	565	4.0	—	0.8
Beaumont	Texas	■	▲	●	100	609	0.9	1.7	—
Corpus Christi	Texas			●	50	—	0.9	0.7	—
Mont Belvieu	Texas			●	100	—	—	2.3	—
Total United States						1,955	6.9	6.0	1.7

Canada
Strathcona	Alberta	■			69.6	197	—	—	—
Nanticoke	Ontario	■			69.6	113	—	—	—
Sarnia	Ontario	■		●	69.6	123	0.3	0.5	—
Total Canada						433	0.3	0.5	—

Europe
Antwerp	Belgium	■		●	100	307	—	0.4	—
Meerhout	Belgium			●	100	—	—	0.5	—
Fos-sur-Mer	France	■			82.9	133	—	—	—
Gravenchon	France	■	▲	●	82.9 / 100 (3)	244	0.4	0.4	0.3
Karlsruhe (4)	Germany	■			25	78	—	—	—
Rotterdam	Netherlands	■	▲	●	100	192	—	—	—
Fawley	United Kingdom	■	▲	●	100	262	—	—	—
Fife	United Kingdom			●	50	—	0.4	—	—
Total Europe						1,216	0.8	1.3	0.3

Asia Pacific
Fujian	China	■		●	25	67	0.3	0.2	0.2
Singapore	Singapore	■	▲	●	100	592	1.9	1.9	0.9
Total Asia Pacific						659	2.2	2.1	1.1

Middle East
Al Jubail	Saudi Arabia		▲	●	50	—	0.7	0.7	—
Yanbu	Saudi Arabia	■		●	50	200	1.0	0.7	0.2
Total Middle East						200	1.7	1.4	0.2

Total Worldwide						4,463	11.9	11.2	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.

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	Total

United States	—	10,722	10,722
Canada	—	2,477	2,477
Europe	169	3,573	3,742
Asia Pacific	284	931	1,215
Latin America	—	523	523
Middle East/Africa	169	255	424
Worldwide	622	18,481	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.


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) 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)

Karen T. McKee	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.

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	—	—	—	$21.9
November 2023	23,692,642	$104.55	21,626,648	$19.7
December 2023	22,318,029	$101.06	21,319,070	$17.5
Total	46,010,671	$102.86	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.
(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.


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.


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.


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.


Equity Compensation Plan Information
	(a)		(b)	(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans [Excluding Securities Reflected in Column (a)]
Equity compensation plans approved by security holders	43,076,160	(1)	—	54,253,587	(2)(3)

Equity compensation plans not approved by security holders	—		—	—

Total	43,076,160		—	54,253,587

(1) The number of restricted stock units to be settled in shares.
(2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 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.

FINANCIAL SECTION


TABLE OF CONTENTS

Business Profile			35
Financial Information			36
Frequently Used Terms			37

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements			42
Overview			43
Business Environment			44
Business Results			50
Liquidity and Capital Resources			64
Capital and Exploration Expenditures			68
Taxes			68
Environmental Matters			69
Market Risks			69
Critical Accounting Estimates			71

Management’s Report on Internal Control Over Financial Reporting			75
Report of Independent Registered Public Accounting Firm			76

Consolidated Financial Statements

Statement of Income			78
Statement of Comprehensive Income			79
Balance Sheet			80
Statement of Cash Flows			81
Statement of Changes in Equity			82

Notes to Consolidated Financial Statements

1. Summary of Accounting Policies			83
2. Russia			87
3. Miscellaneous Financial Information			88
4. Other Comprehensive Income Information			89
5. Cash Flow Information			90
6. Additional Working Capital Information			90
7. Equity Company Information			91
8. Investments, Advances and Long-Term Receivables			93
9. Property, Plant and Equipment and Asset Retirement Obligations			93
10. Accounting for Suspended Exploratory Well Costs			95
11. Leases			97
12. Earnings Per Share			99
13. Financial Instruments and Derivatives			100
14. Long-Term Debt			101
15. Incentive Program			103
16. Litigation and Other Contingencies			104
17. Pension and Other Postretirement Benefits			105
18. Disclosures about Segments and Related Information			111
19. Income and Other Taxes			114
20. Divestment Activities			118
21. Mergers and Acquisitions			119

Supplemental Information on Oil and Gas Exploration and Production Activities			120

BUSINESS PROFILE


	Earnings (Loss) After Income Taxes		Average Capital Employed (Non-GAAP)		Return on Average Capital Employed (Non-GAAP)		Capital and Exploration Expenditures
Financial	2023	2022	2023	2022	2023	2022	2023	2022
	(millions of dollars)		(millions of dollars)		(percent)		(millions of dollars)
Upstream
United States	4,202	11,728	51,957	52,555	8.1	22.3	8,813	6,968
Non-U.S.	17,106	24,751	91,358	93,250	18.7	26.5	10,948	10,034
Total	21,308	36,479	143,315	145,805	14.9	25.0	19,761	17,002

Energy Products
United States	6,123	8,340	12,540	11,787	48.8	70.8	1,195	1,351
Non-U.S.	6,019	6,626	20,010	18,855	30.1	35.1	1,580	1,059
Total	12,142	14,966	32,550	30,642	37.3	48.8	2,775	2,410

Chemical Products
United States	1,626	2,328	14,702	14,694	11.1	15.8	751	1,123
Non-U.S.	11	1,215	13,859	12,513	0.1	9.7	1,962	1,842
Total	1,637	3,543	28,561	27,207	5.7	13.0	2,713	2,965

Specialty Products
United States	1,536	1,190	2,148	2,072	71.5	57.4	63	46
Non-U.S.	1,178	1,225	6,366	6,207	18.5	19.7	391	222
Total	2,714	2,415	8,514	8,279	31.9	29.2	454	268

Corporate and Financing	(1,791)	(1,663)	30,500	16,471	—	—	622	59
Corporate total	36,010	55,740	243,440	228,404	15.0	24.9	26,325	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.


Operating	2023	2022		2023	2022
Net liquids production (thousands of barrels daily)			Refinery throughput (thousands of barrels daily)
United States	803	776	United States	1,848	1,702
Non-U.S.	1,646	1,578	Non-U.S.	2,220	2,328
Total	2,449	2,354	Total	4,068	4,030

Natural gas production available for sale (millions of cubic feet daily)			Energy Products sales (2) (thousands of barrels daily)
United States	2,311	2,551	United States	2,633	2,426
Non-U.S.	5,423	5,744	Non-U.S.	2,828	2,921
Total	7,734	8,295	Total	5,461	5,347

Oil-equivalent production (1) (thousands of oil-equivalent barrels daily)	3,738	3,737	Chemical Products sales (2) (thousands of metric tons)
			United States	6,779	7,270
			Non-U.S.	12,603	11,897
			Total	19,382	19,167

			Specialty Products sales (2) (thousands of metric tons)
			United States	1,962	2,049
			Non-U.S.	5,635	5,762
			Total	7,597	7,810

(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.

FINANCIAL INFORMATION


(millions of dollars, except where stated otherwise)	2023	2022	2021
Sales and other operating revenue	334,697	398,675	276,692






Net income (loss) attributable to ExxonMobil	36,010	55,740	23,040

Earnings (loss) per common share (dollars)	8.89	13.26	5.39
Earnings (loss) per common share – assuming dilution (dollars)	8.89	13.26	5.39

Earnings (loss) to average ExxonMobil share of equity (percent)	18.0	30.7	14.1

Working capital	31,293	28,586	2,511
Ratio of current assets to current liabilities (times)	1.48	1.41	1.04

Additions to property, plant and equipment	29,038	18,338	12,541
Property, plant and equipment, less allowances	214,940	204,692	216,552
Total assets	376,317	369,067	338,923

Exploration expenses, including dry holes	751	1,025	1,054
Research and development costs	879	824	843

Long-term debt	37,483	40,559	43,428
Total debt	41,573	41,193	47,704
Debt to capital (percent)	16.4	16.9	21.4
Net debt to capital (percent) (1)	4.5	5.4	18.9

ExxonMobil share of equity at year-end	204,802	195,049	168,577
ExxonMobil share of equity per common share (dollars)	51.57	47.78	39.77
Weighted average number of common shares outstanding (millions)	4,052	4,205	4,275

Number of regular employees at year-end (thousands) (2)	61.5	62.3	63.0

(1) Debt net of cash.
(2) 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.

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)	2023	2022	2021
Net cash provided by operating activities	55,369	76,797	48,129
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments	4,078	5,247	3,176
Cash flow from operations and asset sales (Non-GAAP)	59,447	82,044	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)	2023	2022	2021
Business uses: asset and liability perspective
Total assets	376,317	369,067	338,923
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable	(61,226)	(68,411)	(52,367)
Total long-term liabilities excluding long-term debt	(60,980)	(56,990)	(63,169)
Noncontrolling interests share of assets and liabilities	(8,878)	(9,205)	(8,746)
Add ExxonMobil share of debt-financed equity company net assets	3,481	3,705	4,001
Total capital employed (Non-GAAP)	248,714	238,166	218,642

Total corporate sources: debt and equity perspective
Notes and loans payable	4,090	634	4,276
Long-term debt	37,483	40,559	43,428
ExxonMobil share of equity	204,802	195,049	168,577
Less noncontrolling interests share of total debt	(1,142)	(1,781)	(1,640)
Add ExxonMobil share of equity company debt	3,481	3,705	4,001
Total capital employed (Non-GAAP)	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)	2023	2022	2021
Net income (loss) attributable to ExxonMobil	36,010	55,740	23,040
Financing costs (after-tax)
Gross third-party debt	(1,175)	(1,213)	(1,196)
ExxonMobil share of equity companies	(307)	(198)	(170)
All other financing costs – net	931	276	11
Total financing costs	(551)	(1,135)	(1,355)
Earnings (loss) excluding financing costs (Non-GAAP)	36,561	56,875	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%

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)	2019				2023
Components of Operating Costs
From ExxonMobil’s Consolidated Statement of Income (U.S. GAAP)
Production and manufacturing expenses	36.8				36.9
Selling, general and administrative expenses	11.4				9.9
Depreciation and depletion (includes impairments)	19.0				20.6
Exploration expenses, including dry holes	1.3				0.8
Non-service pension and postretirement benefit expense	1.2				0.7
Subtotal	69.7				68.9
ExxonMobil's share of equity company expenses (Non-GAAP)	9.1				10.5
Total Adjusted Operating Costs (Non-GAAP)	78.8				79.4

Total Adjusted Operating Costs (Non-GAAP)	78.8				79.4
Less:
Depreciation and depletion (includes impairments)	19.0				20.6
Non-service pension and postretirement benefit expense	1.2				0.7
Other adjustments (includes equity company depreciation and depletion)	3.6				3.7
Total Cash Operating Expenses (Cash Opex) (Non-GAAP)	55.0				54.4

Energy and production taxes (Non-GAAP)	11.0				14.9

		Market	Activity / Other	Structural Savings
Total Cash Operating Expenses (Cash Opex) excluding Energy and Production Taxes (Non-GAAP)	44.0	+3.6	+1.6	-9.7	39.5

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		2023			2022			2021
(millions of dollars)	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total
Earnings (loss) (U.S. GAAP)	4,202	17,106	21,308	11,728	24,751	36,479	3,663	12,112	15,775
Impairments	(1,978)	(686)	(2,664)	—	(3,790)	(3,790)	(263)	(489)	(752)
Gain/(loss) on sale of assets	305	—	305	299	587	886	—	459	459

Tax-related items	184	(126)	58	—	(1,415)	(1,415)	—	—	—

Contractual provisions	—	—	—	—	—	—	—	(250)	(250)
Other	—	—	—	—	1,380	1,380	—	—	—
Identified Items	(1,489)	(812)	(2,301)	299	(3,238)	(2,939)	(263)	(280)	(543)
Earnings (loss) excluding Identified Items (Non-GAAP)	5,691	17,918	23,609	11,429	27,989	39,418	3,926	12,392	16,318


Energy Products		2023			2022			2021
(millions of dollars)	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total
Earnings (loss) (U.S. GAAP)	6,123	6,019	12,142	8,340	6,626	14,966	668	(1,014)	(347)
Impairments	—	—	—	(58)	(216)	(274)	—	—	—


Tax-related items	192	(48)	144	—	(410)	(410)	—	—	—



Identified Items	192	(48)	144	(58)	(626)	(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		2023			2022			2021
(millions of dollars)	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total
Earnings (loss) (U.S. GAAP)	1,626	11	1,637	2,328	1,215	3,543	3,697	3,292	6,989
Impairments	(21)	(273)	(294)	—	—	—	—	—	—


Tax-related items	53	—	53	—	—	—	—	—	—


Other	—	(147)	(147)	—	—	—	—	—	—
Identified Items	32	(420)	(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

FREQUENTLY USED TERMS


Specialty Products		2023			2022			2021
(millions of dollars)	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total
Earnings (loss) (U.S. GAAP)	1,536	1,178	2,714	1,190	1,225	2,415	1,452	1,807	3,259
Impairments	—	(82)	(82)	—	(40)	(40)	—	—	—
Gain/(loss) on sale of assets	—	—	—	—	—	—	498	136	634

Tax-related items	12	5	17	—	—	—	—	—	—


Other	—	(28)	(28)	—	—	—	—	—	—
Identified Items	12	(105)	(93)	—	(40)	(40)	498	136	634
Earnings (loss) excluding Identified Items (Non-GAAP)	1,524	1,283	2,807	1,190	1,265	2,455	954	1,672	2,625


Corporate and Financing (millions of dollars)	2023	2022	2021
Earnings (loss) (U.S. GAAP)	(1,791)	(1,663)	(2,636)
Impairments	—	(98)	—
Gain/(loss) on sale of assets	—	—	(12)

Tax-related items	76	324	—
Severance charges	—	—	(52)

Other	—	76	—
Identified Items	76	302	(64)
Earnings (loss) excluding Identified Items (Non-GAAP)	(1,867)	(1,965)	(2,572)


Corporate Total (millions of dollars)	2023	2022	2021
Net income (loss) attributable to ExxonMobil (U.S. GAAP)	36,010	55,740	23,040
Impairments	(3,040)	(4,202)	(752)
Gain/(loss) on sale of assets	305	886	1,081

Tax-related items	348	(1,501)	—
Severance charges	—	—	(52)
Contractual provisions	—	—	(250)
Other	(175)	1,456	—
Identified Items	(2,562)	(3,361)	27
Earnings (loss) excluding Identified Items (Non-GAAP)	38,572	59,101	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.

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.

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.

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 Source: ExxonMobil 2023 Global Outlook			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.

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.

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.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant oil and natural gas investment needed to meet projected global demand

Projected global oil supply and demand

Million barrels per day


Excludes biofuels; IEA STEPS, IEA APS, and IEA NZE Source: IEA WEO 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

Projected global natural gas supply and demand

Billion cubic feet per day

Natural gas supply gap - option 1 bold.jpg


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.

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.

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 over the past several years enabled the Corporation to capture $9.7 billion of structural cost savings(1) versus 2019, including $2.3 billion of savings during 2023, through 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) 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.

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(1), 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(2), 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.

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.

(2) Based on the October 5, 2023, closing price for ExxonMobil shares and the fixed exchange rate of 2.3234 per Pioneer share.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Upstream Financial Results


(millions of dollars)	2023	2022	2021
Earnings (loss) (U.S. GAAP)
United States	4,202	11,728	3,663
Non-U.S.	17,106	24,751	12,112
Total	21,308	36,479	15,775

Identified Items (1)
United States	(1,489)	299	(263)
Non-U.S.	(812)	(3,238)	(280)
Total	(2,301)	(2,939)	(543)

Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States	5,691	11,429	3,926
Non-U.S.	17,918	27,989	12,392
Total	23,609	39,418	16,318

(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)

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.

Identified Items(1) – 2022 $(2,939) million loss mainly driven by the Russia expropriation $(2,185) million and impacts from additional European taxes $(1,415) million, partly offset by gains of $886 million on the sale of the Romania, U.S. Barnett Shale, and XTO Energy Canada assets; 2023 $(2,301) million loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California.

(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.

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.

Identified Items(1) – 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


	2023	2022	2021
Net production of crude oil, natural gas liquids, bitumen and synthetic oil (thousands of barrels daily)
United States	803	776	721
Canada/Other Americas	664	588	560
Europe	4	4	22
Africa	221	238	248
Asia	721	705	695
Australia/Oceania	36	43	43
Worldwide	2,449	2,354	2,289

Net natural gas production available for sale (millions of cubic feet daily)
United States	2,311	2,551	2,746
Canada/Other Americas	96	148	195
Europe	414	667	808
Africa	125	71	43
Asia	3,490	3,418	3,465
Australia/Oceania	1,298	1,440	1,280
Worldwide	7,734	8,295	8,537

Oil-equivalent production (2) (thousands of oil-equivalent barrels daily)	3,738	3,737	3,712

(2) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Upstream Additional Information
(thousands of barrels daily)	2023	2022
Volumes Reconciliation (Oil-equivalent production) (1)
Prior Year	3,737	3,712
Entitlements - Net Interest	(24)	(44)
Entitlements - Price / Spend / Other	56	(34)
Government Mandates (2)	(28)	71
Divestments	(114)	(71)
Growth / Other (2)	111	103
Current Year	3,738	3,737

(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
(2) 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.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Energy Products Financial Results


(millions of dollars)	2023	2022	2021
Earnings (loss) (U.S. GAAP)
United States	6,123	8,340	668
Non-U.S.	6,019	6,626	(1,014)
Total	12,142	14,966	(347)

Identified Items (1)
United States	192	(58)	—
Non-U.S.	(48)	(626)	—
Total	144	(684)	—

Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States	5,931	8,398	668
Non-U.S.	6,067	7,252	(1,014)
Total	11,998	15,650	(347)

(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)

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 (1) – 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) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.

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 (1) – 2022 $(684) million loss was driven by additional European taxes on the energy sector and impairments.

(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)	2023	2022	2021
Refinery throughput
United States	1,848	1,702	1,623
Canada	407	418	379
Europe	1,166	1,192	1,210
Asia Pacific	498	539	571
Other	149	179	162
Worldwide	4,068	4,030	3,945

Energy Products sales (2)
United States	2,633	2,426	2,267
Non-U.S.	2,828	2,921	2,863
Worldwide	5,461	5,347	5,130

Gasoline, naphthas	2,288	2,232	2,158
Heating oils, kerosene, diesel	1,795	1,774	1,749
Aviation fuels	336	338	220
Heavy fuels	214	235	269
Other energy products	829	768	734
Worldwide	5,461	5,347	5,130

(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.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Chemical Products Financial Results


(millions of dollars)	2023	2022	2021
Earnings (loss) (U.S. GAAP)
United States	1,626	2,328	3,697
Non-U.S.	11	1,215	3,292
Total	1,637	3,543	6,989

Identified Items (1)
United States	32	—	—
Non-U.S.	(420)	—	—
Total	(388)	—	—

Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States	1,594	2,328	3,697
Non-U.S.	431	1,215	3,292
Total	2,025	3,543	6,989

(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)

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 (1) – 2023 $(388) million loss was primarily driven by impairments.

(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.

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)	2023	2022	2021
Chemical product sales (1)
United States	6,779	7,270	7,017
Non-U.S.	12,603	11,897	12,126
Worldwide	19,382	19,167	19,142

(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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Specialty Products

ExxonMobil Specialty Products is a combination of business units that manufacture and market a range of performance products including high-quality lubricants, basestocks, waxes, synthetics, elastomers, and resins. Leveraging ExxonMobil’s proprietary technologies, Specialty Products focuses on providing performance products that help customers improve efficiency in the transportation and industrial sectors.

Specialty Products is well-positioned to help meet growth in lubricants demand through advantaged projects that leverage ExxonMobil's integration, technology, and world-class brands, such as Mobil 1TM.

In 2023, Specialty Products continued to deliver strong earnings from our portfolio of high-value products and brand market position.

Key Recent Events

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Specialty Products Financial Results


(millions of dollars)	2023	2022	2021
Earnings (loss) (U.S. GAAP)
United States	1,536	1,190	1,452
Non-U.S.	1,178	1,225	1,807
Total	2,714	2,415	3,259

Identified Items (1)
United States	12	—	498
Non-U.S.	(105)	(40)	136
Total	(93)	(40)	634

Earnings (loss) excluding Identified Items (1) (Non-GAAP)
United States	1,524	1,190	954
Non-U.S.	1,283	1,265	1,672
Total	2,807	2,455	2,625

(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)

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.

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 (1) – 2021 $634 million gain resulted from the Santoprene divestment; 2022 $(40) million loss from impairments.

(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.

Specialty Products Operational Results


(thousands of metric tons)	2023	2022	2021
Specialty Products sales (2)
United States	1,962	2,049	1,943
Non-U.S.	5,635	5,762	5,723
Worldwide	7,597	7,810	7,666

(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.

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)	2023	2022	2021
Earnings (loss) (U.S. GAAP)	(1,791)	(1,663)	(2,636)
Identified Items (1)	76	302	(64)
Earnings (loss) excluding Identified Items (1) (Non-GAAP)	(1,867)	(1,965)	(2,572)

(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.


2023			Corporate and Financing expenses were $1,791 million in 2023 compared to $1,663 million in 2022, with the increase mainly due to the absence of prior year favorable tax-related items, partly offset by lower financing costs.
2022			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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

LIQUIDITY AND CAPITAL RESOURCES


Sources and Uses of Cash
(millions of dollars)	2023	2022	2021
Net cash provided by/(used in)
Operating activities	55,369	76,797	48,129
Investing activities	(19,274)	(14,742)	(10,235)
Financing activities	(34,297)	(39,114)	(35,423)
Effect of exchange rate changes	105	(78)	(33)
Increase/(decrease) in cash and cash equivalents	1,903	22,863	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.

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.

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.

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)	2023	2022	2021
Debt to capital	16.4	16.9	21.4
Net debt to capital	4.5	5.4	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.

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)	2023			2022
	U.S.	Non-U.S.	Total	U.S.	Non-U.S.	Total
Upstream (including exploration expenses)	8,813	10,948	19,761	6,968	10,034	17,002
Energy Products	1,195	1,580	2,775	1,351	1,059	2,410
Chemical Products	751	1,962	2,713	1,123	1,842	2,965
Specialty Products	63	391	454	46	222	268
Other	622	—	622	59	—	59
Total	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


(millions of dollars)	2023	2022	2021
Income taxes	15,429	20,176	7,636
Effective income tax rate	33%	33%	31%
Total other taxes and duties	32,191	31,455	32,955
Total	47,620	51,631	40,591

2023

Total taxes on the Corporation’s income statement were $47.6 billion in 2023, a decrease of $4.0 billion from 2022. Income tax expense, both current and deferred, was $15.4 billion compared to $20.2 billion in 2022. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ENVIRONMENTAL MATTERS

Environmental Expenditures


(millions of dollars)	2023	2022
Capital expenditures	2,799	1,864
Other expenditures	4,336	3,835
Total	7,135	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 (1)	2023	2022	2021
Crude oil and NGL ($ per barrel)	69.85	87.25	61.89
Natural gas ($ per thousand cubic feet)	4.26	7.48	4.33

(1) Consolidated subsidiaries.

Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings have varied across the Corporation's operating segments. For the year 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.

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.

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.

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.

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.

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.

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.



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)

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.

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.

CONSOLIDATED STATEMENT OF INCOME


(millions of dollars)	Note Reference Number	2023	2022	2021

Revenues and other income
Sales and other operating revenue	18	334,697	398,675	276,692
Income from equity affiliates	7	6,385	11,463	6,657
Other income		3,500	3,542	2,291
Total revenues and other income		344,582	413,680	285,640

Costs and other deductions
Crude oil and product purchases		193,029	228,959	155,164
Production and manufacturing expenses		36,885	42,609	36,035
Selling, general and administrative expenses		9,919	10,095	9,574
Depreciation and depletion (includes impairments)	2, 9	20,641	24,040	20,607
Exploration expenses, including dry holes		751	1,025	1,054
Non-service pension and postretirement benefit expense	17	714	482	786
Interest expense		849	798	947
Other taxes and duties	19	29,011	27,919	30,239
Total costs and other deductions		291,799	335,927	254,406
Income (loss) before income taxes		52,783	77,753	31,234
Income tax expense (benefit)	19	15,429	20,176	7,636
Net income (loss) including noncontrolling interests		37,354	57,577	23,598
Net income (loss) attributable to noncontrolling interests		1,344	1,837	558
Net income (loss) attributable to ExxonMobil		36,010	55,740	23,040

Earnings (loss) per common share (dollars)	12	8.89	13.26	5.39

Earnings (loss) per common share - assuming dilution (dollars)	12	8.89	13.26	5.39

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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	1,241	(3,482)	(872)
Adjustment for foreign exchange translation (gain)/loss included in net income	609	—	(2)
Postretirement benefits reserves adjustment (excluding amortization)	(369)	3,395	3,118
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	61	403	925
Total other comprehensive income (loss)	1,542	316	3,169
Comprehensive income (loss) including noncontrolling interests	38,896	57,893	26,767
Comprehensive income (loss) attributable to noncontrolling interests	1,605	1,659	786
Comprehensive income (loss) attributable to ExxonMobil	37,291	56,234	25,981

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

CONSOLIDATED BALANCE SHEET


(millions of dollars)	Note Reference Number	December 31, 2023	December 31, 2022

ASSETS
Current assets
Cash and cash equivalents		31,539	29,640
Cash and cash equivalents – restricted		29	25
Notes and accounts receivable – net	6	38,015	41,749
Inventories
Crude oil, products and merchandise	3	20,528	20,434
Materials and supplies		4,592	4,001
Other current assets		1,906	1,782
Total current assets		96,609	97,631
Investments, advances and long-term receivables	8	47,630	49,793
Property, plant and equipment, at cost, less accumulated depreciation and depletion	9	214,940	204,692
Other assets, including intangibles – net		17,138	16,951
Total Assets		376,317	369,067

LIABILITIES
Current liabilities
Notes and loans payable	6	4,090	634
Accounts payable and accrued liabilities	6	58,037	63,197
Income taxes payable		3,189	5,214
Total current liabilities		65,316	69,045
Long-term debt	14	37,483	40,559
Postretirement benefits reserves	17	10,496	10,045
Deferred income tax liabilities	19	24,452	22,874
Long-term obligations to equity companies		1,804	2,338
Other long-term obligations		24,228	21,733
Total Liabilities		163,779	166,594

Commitments and contingencies	16

EQUITY
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued)		17,781	15,752
Earnings reinvested		453,927	432,860
Accumulated other comprehensive income	4	(11,989)	(13,270)
Common stock held in treasury (4,048 million shares in 2023 and 3,937 million shares in 2022)		(254,917)	(240,293)
ExxonMobil share of equity		204,802	195,049
Noncontrolling interests		7,736	7,424
Total Equity		212,538	202,473
Total Liabilities and Equity		376,317	369,067

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

CONSOLIDATED STATEMENT OF CASH FLOWS


(millions of dollars)		Note Reference Number	2023	2022	2021

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) including noncontrolling interests			37,354	57,577	23,598
Adjustments for noncash transactions
Depreciation and depletion (includes impairments)		2, 9	20,641	24,040	20,607
Deferred income tax charges/(credits)		19	634	3,758	303
Postretirement benefits expense in excess of/(less than) net payments			90	(2,981)	754
Other long-term obligation provisions in excess of/(less than) payments			(1,501)	(1,932)	50
Dividends received greater than/(less than) equity in current earnings of equity companies			509	(2,446)	(668)
Changes in operational working capital, excluding cash and debt
Notes and accounts receivable reduction/(increase)			4,370	(11,019)	(12,098)
Inventories reduction/(increase)			(3,472)	(6,947)	(489)
Other current assets reduction/(increase)			(426)	(688)	(71)
Accounts and other payables increase/(reduction)			(4,727)	18,460	16,820
Net (gain)/loss on asset sales		5	(513)	(1,034)	(1,207)
All other items - net			2,410	9	530
Net cash provided by operating activities			55,369	76,797	48,129

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant and equipment			(21,919)	(18,407)	(12,076)
Proceeds from asset sales and returns of investments			4,078	5,247	3,176
Additional investments and advances			(2,995)	(3,090)	(2,817)
Other investing activities including collection of advances			1,562	1,508	1,482
Net cash used in investing activities			(19,274)	(14,742)	(10,235)

CASH FLOWS FROM FINANCING ACTIVITIES
Additions to long-term debt (1)			939	637	46
Reductions in long-term debt			(15)	(5)	(8)
Additions to short-term debt			—	198	12,687
Reductions in short-term debt			(879)	(8,075)	(29,396)
Additions/(reductions) in debt with three months or less maturity			(284)	25	(2,983)
Contingent consideration payments			(68)	(58)	(30)
Cash dividends to ExxonMobil shareholders			(14,941)	(14,939)	(14,924)
Cash dividends to noncontrolling interests			(531)	(267)	(224)
Changes in noncontrolling interests			(770)	(1,475)	(436)
Common stock acquired			(17,748)	(15,155)	(155)
Net cash provided by (used in) financing activities			(34,297)	(39,114)	(35,423)

Effects of exchange rate changes on cash			105	(78)	(33)
Increase/(decrease) in cash and cash equivalents			1,903	22,863	2,438
Cash and cash equivalents at beginning of year			29,665	6,802	4,364
Cash and cash equivalents at end of year			31,568	29,665	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.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


	ExxonMobil Share of Equity

(millions of dollars)	Common Stock	Earnings Reinvested	Accumulated Other Comprehensive Income	Common Stock Held in Treasury	ExxonMobil Share of Equity	Non-controlling Interests	Total Equity

Balance as of December 31, 2020	15,688	383,943	(16,705)	(225,776)	157,150	6,980	164,130
Amortization of stock-based awards	534	—	—	—	534	—	534
Other	(476)	—	—	—	(476)	115	(361)
Net income (loss) for the year	—	23,040	—	—	23,040	558	23,598
Dividends - common shares	—	(14,924)	—	—	(14,924)	(224)	(15,148)

Other comprehensive income	—	—	2,941	—	2,941	228	3,169
Share repurchases, at cost	—	—	—	(155)	(155)	(551)	(706)

Dispositions	—	—	—	467	467	—	467
Balance as of December 31, 2021	15,746	392,059	(13,764)	(225,464)	168,577	7,106	175,683
Amortization of stock-based awards	481	—	—	—	481	—	481
Other	(475)	—	—	—	(475)	405	(70)
Net income (loss) for the year	—	55,740	—	—	55,740	1,837	57,577
Dividends - common shares	—	(14,939)	—	—	(14,939)	(267)	(15,206)

Other comprehensive income	—	—	494	—	494	(178)	316
Share repurchases, at cost	—	—	—	(15,295)	(15,295)	(1,479)	(16,774)
Dispositions	—	—	—	466	466	—	466
Balance as of December 31, 2022	15,752	432,860	(13,270)	(240,293)	195,049	7,424	202,473
Amortization of stock-based awards	565	—	—	—	565	—	565
Other	(514)	(2)	—	—	(516)	89	(427)
Net income (loss) for the year	—	36,010	—	—	36,010	1,344	37,354
Dividends - common shares	—	(14,941)	—	—	(14,941)	(531)	(15,472)

Other comprehensive income	—	—	1,281	—	1,281	261	1,542
Share repurchases, at cost	—	—	—	(17,993)	(17,993)	(851)	(18,844)
Issued for acquisitions	1,978	—	—	2,866	4,844	—	4,844
Dispositions	—	—	—	503	503	—	503
Balance as of December 31, 2023	17,781	453,927	(11,989)	(254,917)	204,802	7,736	212,538


Common Stock Share Activity (millions of shares)	Issued	Held in Treasury	Outstanding

Balance as of December 31, 2020	8,019	(3,786)	4,233
Share repurchases, at cost	—	(2)	(2)

Dispositions	—	8	8
Balance as of December 31, 2021	8,019	(3,780)	4,239
Share repurchases, at cost	—	(165)	(165)

Dispositions	—	8	8
Balance as of December 31, 2022	8,019	(3,937)	4,082
Share repurchases, at cost	—	(165)	(165)
Issued for acquisitions	—	46	46
Dispositions	—	8	8
Balance as of December 31, 2023	8,019	(4,048)	3,971

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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 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.

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.

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.

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.

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.

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.

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.

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)	Dec 31, 2023	Dec 31, 2022
Crude oil	6,944	6,909
Petroleum products	6,248	6,291
Chemical products (1)	3,930	3,806
Gas/other	3,406	3,428
Total	20,528	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.

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	(10,614)	(6,091)	(16,705)
Current period change excluding amounts reclassified from accumulated other comprehensive income	(883)	2,938	2,055
Amounts reclassified from accumulated other comprehensive income	(2)	888	886
Total change in accumulated other comprehensive income	(885)	3,826	2,941
Balance as of December 31, 2021	(11,499)	(2,265)	(13,764)
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)	(3,092)	3,205	113
Amounts reclassified from accumulated other comprehensive income	—	381	381
Total change in accumulated other comprehensive income	(3,092)	3,586	494
Balance as of December 31, 2022	(14,591)	1,321	(13,270)
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)	1,108	(305)	803
Amounts reclassified from accumulated other comprehensive income	427	51	478
Total change in accumulated other comprehensive income	1,535	(254)	1,281
Balance as of December 31, 2023	(13,056)	1,067	(11,989)

(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)	(609)	—	2
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)	(81)	(519)	(1,229)


Income Tax (Expense)/Credit For Components of Other Comprehensive Income (millions of dollars)	2023	2022	2021

Foreign exchange translation adjustment	341	54	(114)
Postretirement benefits reserves adjustment (excluding amortization)	200	(1,120)	(983)
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	(20)	(116)	(304)
Total	521	(1,182)	(1,401)

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)	2023	2022	2021

Income taxes paid	15,473	15,364	5,341

Cash interest paid
Included in cash flows from operating activities	584	666	819
Capitalized, included in cash flows from investing activities	1,152	838	655
Total cash interest paid	1,736	1,504	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	30,296	32,844
Other, less reserves of $101 million and $402 million	7,719	8,905
Total	38,015	41,749

Notes and loans payable
Bank loans	6	379
Commercial paper	75	74
Long-term debt due within one year	4,009	181
Total	4,090	634

Accounts payable and accrued liabilities
Trade payables	31,249	33,169
Payables to equity companies	11,885	14,585
Accrued taxes other than income taxes	3,817	3,969
Other	11,086	11,474
Total	58,037	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.

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)	2023		2022		2021
	Total	ExxonMobil Share	Total	ExxonMobil Share	Total	ExxonMobil Share

Total revenues	132,783	40,682	183,812	57,528	116,972	34,995
Income before income taxes	35,999	10,078	61,550	19,279	35,142	9,278
Income taxes	11,404	3,085	23,149	7,603	11,010	2,763
Income from equity affiliates	24,595	6,993	38,401	11,676	24,132	6,515

Current assets	53,081	18,713	77,457	24,994	45,267	15,542
Long-term assets	150,198	40,986	153,186	42,921	150,699	41,614
Total assets	203,279	59,699	230,643	67,915	195,966	57,156

Current liabilities	30,721	9,652	53,640	15,555	28,862	8,297
Long-term liabilities	57,237	17,059	62,009	18,929	63,138	19,084
Net assets	115,321	32,988	114,994	33,431	103,966	29,775

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

Upstream
Barzan Gas Company Limited			7
BEB Erdgas und Erdoel GmbH & Co. KG			50
Caspian Pipeline Consortium			8
Coral FLNG S.A.			25
Cross Timbers Energy LLC			50
GasTerra B.V.			25
Golden Pass LNG Terminal LLC			30
Golden Pass Pipeline LLC			30
Marine Well Containment Company LLC			10
Mozambique Rovuma Venture S.p.A.			36
Nederlandse Aardolie Maatschappij B.V.			50
Papua New Guinea Liquefied Natural Gas Global Company LDC			33
Permian Highway Pipeline LLC			17
QatarEnergy LNG N (2)			24
QatarEnergy LNG NFE (3)			25
QatarEnergy LNG S (1)			25
QatarEnergy LNG S (2)			31
QatarEnergy LNG S (3)			30
South Hook LNG Terminal Company Limited			24
Tengizchevroil LLP			25
Terminale GNL Adriatico S.r.l.			71

Energy Products, Chemical Products, and/or Specialty Products
Al-Jubail Petrochemical Company			50
Alberta Products Pipe Line Ltd.			45
Fujian Refining & Petrochemical Co. Ltd.			25
Gulf Coast Growth Ventures LLC			50
Infineum USA L.P.			50
Permian Express Partners LLC			12
Saudi Aramco Mobil Refinery Company Ltd.			50
Saudi Yanbu Petrochemical Co.			50

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	34,080	34,522
Advances, net of allowances of $33 million and $28 million	7,527	8,049
Total equity method company investments and advances	41,607	42,571
Equity securities carried at fair value and other investments at adjusted cost basis	177	278
Long-term receivables and miscellaneous, net of reserves of $1,966 million and $1,623 million	5,846	6,944
Total	47,630	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	359,031	148,245	350,748	144,146
Energy Products	57,400	27,284	58,393	26,765
Chemical Products	38,801	20,329	36,322	19,064
Specialty Products	9,385	4,378	8,895	4,303
Other	22,768	14,704	18,335	10,414
Total	487,385	214,940	472,693	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.

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	10,491	10,630	11,247
Accretion expense and other provisions	734	744	548
Reduction due to property sales	(288)	(328)	(1,002)
Payments made	(693)	(518)	(444)
Liabilities incurred	831	119	42
Foreign currency translation	124	(330)	(147)
Revisions	1,790	174	386
Balance at December 31	12,989	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.

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)	2023	2022	2021

Balance beginning at January 1	3,512	4,120	4,382
Additions pending the determination of proved reserves	200	378	420
Charged to expense	(95)	(259)	(325)
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(142)	(142)	(328)
Divestments/Other	84	(585)	(29)
Ending balance at December 31	3,559	3,512	4,120
Ending balance attributed to equity companies included above	306	306	306


Period-end capitalized suspended exploratory well costs (millions of dollars)	2023	2022	2021

Capitalized for a period of one year or less	200	378	420
Capitalized for a period of between one and five years	1,030	969	1,642
Capitalized for a period of between five and ten years	1,411	1,410	1,657
Capitalized for a period of greater than ten years	918	755	401
Capitalized for a period greater than one year - subtotal	3,359	3,134	3,700
Total	3,559	3,512	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.


	2023	2022	2021

Number of projects that only have exploratory well costs capitalized for a period of one year or less	—	10	4
Number of projects that have exploratory well costs capitalized for a period greater than one year	31	26	30
Total	31	36	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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides additional detail for those 15 projects, which total $2,389 million.


Country/Project	December 31, 2023	Years Wells Drilled / Acquired			Comment
	(millions of dollars)

Angola
Block 32 Central NE Hub	66	2007	-	2021	Evaluating development plan to tie into existing infrastructure.

Argentina
La Invernada	72	2014			Evaluating development plan to tie into planned infrastructure.

Australia
Gorgon Area Ullage	308	1994	-	2015	Evaluating development plans to tie into existing LNG facilities.

Canada
Hibernia North	25	2019			Awaiting capacity in existing/planned infrastructure.

Guyana
Whiptail	178	2019	-	2022	Continuing discussions with the government regarding development plan.

Kazakhstan
Kairan	53	2004	-	2007	Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan.

Mozambique
Rovuma LNG Phase 1	150	2017			Progressing development plan to tie into planned LNG facilities.
Rovuma LNG Future Non-Straddling Train	120	2017			Evaluating/progressing development plan to tie into planned LNG facilities.
Rovuma LNG Unitized Trains	35	2017			Evaluating/progressing development plan to tie into planned LNG facilities.

Nigeria
Bonga North	34	2004	-	2009	Progressing development plan to tie into existing/planned infrastructure.

Papua New Guinea
Papua LNG	246	2017			Evaluating/progressing development plans.
Muruk	165	2017	-	2019	Evaluating/progressing development plans.
P'nyang	116	2012	-	2018	Evaluating/progressing development plans.

Tanzania
Block 2	525	2012	-	2015	Evaluating development alternatives, while continuing discussions with the government regarding development plan.

Vietnam
Blue Whale	296	2011	-	2015	Evaluating/progressing development plans.

Total 2023 (15 projects)	2,389

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 Leases			Finance Leases
	2023	2022	2021	2023	2022	2021

Operating lease cost	1,976	1,776	1,542
Short-term and other (net of sublease rental income)	1,563	1,389	1,351
Amortization of right of use assets				107	243	133
Interest on lease liabilities				140	210	158
Total (1)	3,539	3,165	2,893	247	453	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)	Operating Leases				Finance Leases
	December 31, 2023		December 31, 2022		December 31, 2023		December 31, 2022

Right of use assets
Included in Other assets, including intangibles - net	6,849		6,451
Included in Property, plant and equipment - net					2,712		2,090
Total right of use assets	6,849		6,451		2,712		2,090

Lease liability due within one year
Included in Accounts payable and accrued liabilities	1,617		1,527		5		5
Included in Notes and loans payable					95		69
Long-term lease liability
Included in Other long-term obligations	4,393		4,067
Included in Long-term debt					1,821		1,389
Included in Long-term obligations to equity companies					121		126
Total lease liability (2)	6,010		5,594		2,042		1,589

Weighted-average remaining lease term (years)	8		9		26		22
Weighted-average discount rate (percent)	3.9	%	2.4	%	7.2	%	8.0	%

(2) Includes $2,032 million and $1,646 million for drilling rigs and related equipment operating leases in 2023 and 2022, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Maturity Analysis of Lease Liabilities (millions of dollars)	Operating Leases	Finance Leases
	December 31, 2023

2024	1,807	243
2025	1,464	237
2026	1,046	234
2027	577	224
2028	307	241
2029 and beyond	1,781	2,256
Total lease payments	6,982	3,435
Discount to present value	(972)	(1,393)
Total lease liability	6,010	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)	Operating Leases			Finance Leases
	2023	2022	2021	2023	2022	2021

Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities	1,135	1,119	1,135	20	20	20
Cash flows from investing activities	758	500	291
Cash flows from financing activities				86	149	110

Noncash right of use assets recorded for lease liabilities
In exchange for lease liabilities during the period	2,161	1,997	1,405	529	73	200

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. Earnings Per Share


Earnings per common share	2023	2022	2021
Net income (loss) attributable to ExxonMobil (millions of dollars)	36,010	55,740	23,040

Weighted-average number of common shares outstanding (millions of shares) (1)	4,052	4,205	4,275

Earnings (loss) per common share (dollars) (2)	8.89	13.26	5.39

Dividends paid per common share (dollars)	3.68	3.55	3.49

(1) Includes restricted shares not vested.
(2) The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown.

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:


	December 31, 2023

	Fair Value
(millions of dollars)	Level 1	Level 2	Level 3	Total Gross Assets & Liabilities	Effect of Counterparty Netting	Effect of Collateral Netting	Difference in Carrying Value and Fair Value	Net Carrying Value
Assets
Derivative assets (1)	4,544	1,731	—	6,275	(5,177)	(528)	—	570
Advances to/receivables from equity companies (2)(6)	—	2,517	4,491	7,008	—	—	519	7,527
Other long-term financial assets (3)	1,389	—	944	2,333	—	—	202	2,535

Liabilities
Derivative liabilities (4)	4,056	1,608	—	5,664	(5,177)	(40)	—	447
Long-term debt (5)	30,556	2,004	—	32,560	—	—	3,102	35,662
Long-term obligations to equity companies (6)	—	—	1,896	1,896	—	—	(92)	1,804
Other long-term financial liabilities (7)	—	—	697	697	—	—	45	742


	December 31, 2022

	Fair Value
(millions of dollars)	Level 1	Level 2	Level 3	Total Gross Assets & Liabilities	Effect of Counterparty Netting	Effect of Collateral Netting	Difference in Carrying Value and Fair Value	Net Carrying Value
Assets
Derivative assets (1)	4,309	3,455	—	7,764	(5,778)	(969)	—	1,017
Advances to/receivables from equity companies (2)(6)	—	2,406	4,958	7,364	—	—	685	8,049
Other long-term financial assets (3)	1,208	—	1,413	2,621	—	—	346	2,967

Liabilities
Derivative liabilities (4)	3,417	3,264	—	6,681	(5,778)	(79)	—	824
Long-term debt (5)	33,112	1,880	6	34,998	—	—	4,173	39,171
Long-term obligations to equity companies (6)	—	—	2,467	2,467	—	—	(129)	2,338
Other long-term financial liabilities (7)	—	—	679	679	—	—	38	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) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles - net.
(4) Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations.
(5) Excluding finance lease obligations.
(6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the 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)	December 31,	December 31,
	2023	2022

Crude oil (barrels)	(7)	4
Petroleum products (barrels)	(43)	(52)
Natural gas (MMBTUs)	(560)	(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)	2023	2022	2021

Sales and other operating revenue	986	(1,763)	(3,818)
Crude oil and product purchases	79	314	48
Total	1,065	(1,449)	(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 Rate (1)	Dec 31, 2023	Dec 31, 2022

Exxon Mobil Corporation (2)
3.176% notes due 2024		—	1,000
2.019% notes due 2024		—	1,000
2.709% notes due 2025		1,750	1,750
2.992% notes due 2025		2,767	2,781
3.043% notes due 2026		2,500	2,500
2.275% notes due 2026		1,000	1,000
3.294% notes due 2027		1,000	1,000
2.440% notes due 2029		1,250	1,250
3.482% notes due 2030		2,000	2,000
2.610% notes due 2030		2,000	2,000
2.995% notes due 2039		750	750
4.227% notes due 2040		2,080	2,084
3.567% notes due 2045		1,000	1,000
4.114% notes due 2046		2,500	2,500
3.095% notes due 2049		1,500	1,500
4.327% notes due 2050		2,750	2,750
3.452% notes due 2051		2,750	2,750
Exxon Mobil Corporation - Euro-denominated
0.142% notes due 2024		—	1,600
0.524% notes due 2028		1,105	1,066
0.835% notes due 2032		1,105	1,066
1.408% notes due 2039		1,105	1,066
XTO Energy Inc. (3)
6.100% senior notes due 2036		189	189
6.750% senior notes due 2037		286	289
6.375% senior notes due 2038		223	224



Industrial revenue bonds due 2022-2051	3.080%	2,123	2,245



Finance leases & other obligations	5.985%	3,838	3,299
Debt issuance costs		(88)	(100)
Total long-term debt		37,483	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	2023
	Shares	Weighted-Average Grant-Date Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	37,573	67.47
Awards issued in 2023	9,247	110.84
Vested	(8,572)	67.75
Forfeited	(436)	73.62
Issued and outstanding at December 31	37,812	77.94


Value of restricted stock units	2023	2022	2021
Grant price (dollars)	103.16	110.46	62.76

Value at date of grant:	(millions of dollars)
Units settled in stock	900	931	461
Units settled in cash	101	106	49
Total value	1,001	1,037	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.


	December 31, 2023

(millions of dollars)	Equity Company Obligations (1)	Other Third-Party Obligations	Total

Guarantees
Debt-related	1,151	149	1,300
Other	711	5,796	6,507
Total	1,862	5,945	7,807

(1) ExxonMobil share.

Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition.

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.


	Pension Benefits				Other Postretirement Benefits

(millions of dollars, except where stated otherwise)	U.S.		Non-U.S.
	2023	2022	2023	2022	2023	2022

Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate (percent)	5.30	5.60	4.30	4.90	5.30	5.60
Long-term rate of compensation increase (percent)	4.50	4.50	4.50	5.20	4.50	4.50

Change in benefit obligation
Benefit obligation at January 1	12,350	18,511	19,342	29,492	5,211	7,265
Service cost	466	712	323	570	78	138
Interest cost	664	518	922	614	276	216
Actuarial loss/(gain) (1)	550	(4,432)	1,393	(7,742)	176	(1,990)
Benefits paid (2)(3)	(870)	(2,959)	(1,214)	(1,415)	(545)	(492)
Foreign exchange rate changes	—	—	515	(2,258)	11	(47)
Amendments, divestments and other	(17)	—	46	81	(193)	121
Benefit obligation at December 31	13,143	12,350	21,327	19,342	5,014	5,211
Accumulated benefit obligation at December 31	11,033	10,367	19,769	18,047	—	—

(1) Actuarial loss/(gain) primarily reflects lower discount rates.
(2) Benefit payments for funded and unfunded plans.
(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.


	Pension Benefits				Other Postretirement Benefits

(millions of dollars)	U.S.		Non-U.S.
	2023	2022	2023	2022	2023	2022

Change in plan assets
Fair value at January 1	10,989	13,266	16,757	24,880	348	440
Actual return on plan assets	1,121	(3,265)	1,484	(5,287)	36	(66)
Foreign exchange rate changes	—	—	492	(2,012)	—	—
Company contribution	—	3,596	615	655	38	27
Benefits paid (1)	(743)	(2,608)	(878)	(1,070)	(51)	(53)
Other	—	—	(39)	(409)	—	—
Fair value at December 31	11,367	10,989	18,431	16,757	371	348

(1) Benefit payments for funded plans.

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.


	Pension Benefits

(millions of dollars)	U.S.		Non-U.S.
	2023	2022	2023	2022

Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans	(271)	(23)	1,028	1,019
Unfunded plans	(1,505)	(1,338)	(3,924)	(3,604)
Total	(1,776)	(1,361)	(2,896)	(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.


	Pension Benefits				Other Postretirement Benefits

(millions of dollars)	U.S.		Non-U.S.
	2023	2022	2023	2022	2023	2022
Assets in excess of/(less than) benefit obligation
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	—	—	1,895	1,962	—	—
Current liabilities	(201)	(168)	(225)	(254)	(288)	(304)
Postretirement benefits reserves	(1,575)	(1,193)	(4,566)	(4,293)	(4,355)	(4,559)
Total recorded	(1,776)	(1,361)	(2,896)	(2,585)	(4,643)	(4,863)

Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)	744	897	1,364	846	(1,453)	(1,726)
Prior service cost	(283)	(295)	401	278	(459)	(190)
Total recorded in accumulated other comprehensive income	461	602	1,765	1,124	(1,912)	(1,916)

(1) Fair value of assets less benefit obligation shown on the preceding page.

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.


	Pension Benefits						Other Postretirement Benefits

(millions of dollars, except where stated otherwise)	U.S.			Non-U.S.
	2023	2022	2021	2023	2022	2021	2023	2022	2021

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
Discount rate (percent)	5.60	3.00	2.80	4.90	2.20	1.60	5.60	3.10	2.80
Long-term rate of return on funded assets (percent)	5.20	4.60	5.30	4.20	3.50	4.10	4.70	3.80	4.60
Long-term rate of compensation increase (percent)	4.50	4.50	5.50	5.20	4.20	4.20	4.50	4.50	5.50

Components of net periodic benefit cost
Service cost	466	712	919	323	570	774	78	138	188
Interest cost	664	518	558	922	614	526	276	216	221
Expected return on plan assets	(532)	(560)	(722)	(688)	(815)	(1,031)	(14)	(14)	(19)
Amortization of actuarial loss/(gain)	85	156	244	108	180	420	(122)	6	76
Amortization of prior service cost	(29)	(29)	(23)	52	43	57	(42)	(42)	(42)
Net pension enhancement and curtailment/settlement cost	29	205	489	5	4	32	—	—	—
Net periodic benefit cost	683	1,002	1,465	722	596	778	176	304	424

Changes in amounts recorded in accumulated other comprehensive income:
Net actuarial loss/(gain)	(39)	(607)	(504)	602	(1,641)	(2,361)	154	(1,910)	(891)
Amortization of actuarial (loss)/gain	(114)	(361)	(733)	(108)	(183)	(430)	122	(6)	(76)
Prior service cost/(credit)	(17)	—	(72)	153	84	92	(312)	—	—
Amortization of prior service (cost)/credit	29	29	23	(52)	(40)	(55)	42	42	42
Foreign exchange rate changes	—	—	—	46	(199)	(255)	(2)	(7)	—
Total recorded in other comprehensive income	(141)	(939)	(1,286)	641	(1,979)	(3,009)	4	(1,881)	(925)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	542	63	179	1,363	(1,383)	(2,231)	180	(1,577)	(501)

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:


	Total Pension and Other Postretirement Benefits

(millions of dollars)	2023	2022	2021

(Charge)/credit to other comprehensive income, before tax
U.S. pension	141	939	1,286
Non-U.S. pension	(641)	1,979	3,009
Other postretirement benefits	(4)	1,881	925
Total (charge)/credit to other comprehensive income, before tax	(504)	4,799	5,220
(Charge)/credit to income tax (see Note 4)	180	(1,236)	(1,287)
(Charge)/credit to investment in equity companies	16	235	110
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax	(308)	3,798	4,043
Charge/(credit) to equity of noncontrolling interests	54	(212)	(217)
(Charge)/credit to other comprehensive income attributable to ExxonMobil	(254)	3,586	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						Non-U.S. Pension

(millions of dollars)	Fair Value Measurement at December 31, 2023, Using:						Fair Value Measurement at December 31, 2023, Using:
	Level 1	Level 2		Level 3	Net Asset Value	Total	Level 1		Level 2		Level 3	Net Asset Value	Total

Asset category:
Equity securities
U.S.	—	—		—	2,114	2,114	—		—		—	2,642	2,642
Non-U.S.	—	—		—	1,344	1,344	52	(1)	—		—	1,688	1,740
Private equity	—	—		—	375	375	—		—		—	294	294
Debt securities
Corporate	—	4,699	(2)	—	1	4,700	—		61	(2)	—	4,370	4,431
Government	—	2,650	(2)	—	2	2,652	134	(3)	171	(2)	—	8,429	8,734
Asset-backed	—	—		—	1	1	—		22	(2)	—	221	243
Other	—	—		—	—	—	—		—		—	4	4
Real Estate	—	—		—	—	—	—		—		—	70	70
Cash	—	—		—	178	178	189		17	(4)	—	45	251
Total at fair value	—	7,349		—	4,015	11,364	375		271		—	17,763	18,409
Insurance contracts at contract value						3							22
Total plan assets						11,367							18,431

(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.


	Other Postretirement

(millions of dollars)	Fair Value Measurement at December 31, 2023, Using:
	Level 1		Level 2		Level 3	Net Asset Value	Total

Asset category:
Equity securities
U.S.	84	(1)	—		—	—	84
Non-U.S.	40	(1)	—		—	—	40
Debt securities
Corporate	—		61	(2)	—	—	61
Government	—		182	(2)	—	—	182
Asset-backed	—		3	(2)	—	—	3
Cash	—		1		—	—	1
Total at fair value	124		247		—	—	371

(1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

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						Non-U.S. Pension

(millions of dollars)	Fair Value Measurement at December 31, 2022, Using:						Fair Value Measurement at December 31, 2022, Using:
	Level 1	Level 2		Level 3	Net Asset Value	Total	Level 1		Level 2		Level 3	Net Asset Value	Total

Asset category:
Equity securities
U.S.	—	—		—	1,726	1,726	—		—		—	2,318	2,318
Non-U.S.	—	—		—	1,131	1,131	61	(1)	—		—	1,676	1,737
Private equity	—	—		—	506	506	—		—		—	472	472
Debt securities
Corporate	—	4,582	(2)	—	1	4,583	—		63	(2)	—	4,199	4,262
Government	—	2,869	(2)	—	2	2,871	202	(3)	144	(2)	—	7,189	7,535
Asset-backed	—	—		—	1	1	—		22	(2)	—	185	207
Cash	—	—		—	168	168	88		40	(4)	—	77	205
Total at fair value	—	7,451		—	3,535	10,986	351		269		—	16,116	16,736
Insurance contracts at contract value						3							21
Total plan assets						10,989							16,757

(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.


	Other Postretirement

(millions of dollars)	Fair Value Measurement at December 31, 2022, Using:
	Level 1		Level 2		Level 3	Net Asset Value	Total

Asset category:
Equity securities
U.S.	70	(1)	—		—	—	70
Non-U.S.	37	(1)	—		—	—	37
Debt securities
Corporate	—		59	(2)	—	—	59
Government	—		175	(2)	—	—	175
Asset-backed	—		4	(2)	—	—	4
Cash	—		3		—	—	3
Total at fair value	107		241		—	—	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:


	Pension Benefits

(millions of dollars)	U.S.		Non-U.S.
	2023	2022	2023	2022

For funded pension plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	—	—	1,145	1,098
Fair value of plan assets	—	—	562	400

For funded pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	11,638	11,012	2,334	1,956
Fair value of plan assets	11,367	10,989	1,465	1,012

For unfunded pension plans:
Projected benefit obligation	1,505	1,338	3,924	3,604
Accumulated benefit obligation	1,173	1,045	3,592	3,261

All other postretirement benefit plans are unfunded or underfunded.


	Pension Benefits		Other Postretirement Benefits

(millions of dollars)	U.S.	Non-U.S.	Gross	Medicare Subsidy Receipt

Contributions expected in 2024	—	275	—	—
Benefit payments expected in:
2024	1,053	1,200	363	—
2025	1,053	1,158	356	—
2026	1,064	1,144	347	1
2027	1,066	1,185	342	1
2028	1,087	1,216	339	1
2029 - 2033	5,644	6,116	1,710	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		Chemical Products		Specialty Products		Corporate and Financing	Corporate Total
	U.S.	Non-U.S.	U.S.	Non-U.S.	U.S.	Non-U.S.	U.S.	Non-U.S.

As of December 31, 2023
Earnings (loss) after income tax	4,202	17,106	6,123	6,019	1,626	11	1,536	1,178	(1,791)	36,010
Earnings of equity companies included above	63	5,550	140	131	126	761	—	(25)	(361)	6,385
Sales and other operating revenue	9,500	16,074	103,868	164,515	7,951	14,314	6,044	12,363	68	334,697
Intersegment revenue	20,971	38,982	23,481	28,258	7,991	3,643	2,570	555	244	—
Depreciation and depletion expense	8,863	7,737	765	797	605	706	93	222	853	20,641
Interest revenue	—	—	—	—	—	—	—	—	1,628	1,628
Interest expense	82	74	4	7	2	2	—	2	676	849
Income tax expense (benefit)	1,016	10,593	1,543	1,492	396	158	458	235	(462)	15,429
Additions to property, plant and equipment	10,372	8,217	1,106	1,455	600	1,775	81	370	5,062	29,038
Investments in equity companies	4,436	21,485	406	1,135	3,086	2,700	—	952	(120)	34,080
Total assets	67,452	138,914	32,123	42,337	17,599	17,076	2,620	8,379	49,817	376,317

As of December 31, 2022
Earnings (loss) after income tax	11,728	24,751	8,340	6,626	2,328	1,215	1,190	1,225	(1,663)	55,740
Earnings of equity companies included above	411	10,133	126	322	91	771	—	(23)	(368)	11,463
Sales and other operating revenue	14,579	30,585	117,824	188,153	10,670	16,949	6,152	13,727	36	398,675
Intersegment revenue	25,658	46,076	29,001	36,894	9,081	5,201	2,587	825	241	—
Depreciation and depletion expense	5,791	14,013	741	1,246	542	446	95	193	973	24,040
Interest revenue	—	—	—	—	—	—	—	—	446	446
Interest expense	51	38	1	7	—	1	—	1	699	798
Income tax expense (benefit)	3,330	11,575	2,615	2,420	520	292	334	252	(1,162)	20,176
Additions to property, plant and equipment	5,940	6,441	1,141	964	1,026	1,692	37	200	897	18,338
Investments in equity companies	4,893	21,502	368	1,154	3,124	2,417	—	1,177	(113)	34,522
Total assets	66,695	139,764	31,729	41,836	17,342	15,875	2,839	8,316	44,671	369,067

As of December 31, 2021
Earnings (loss) after income tax	3,663	12,112	668	(1,014)	3,697	3,292	1,452	1,807	(2,636)	23,040
Earnings of equity companies included above	288	5,535	122	100	(139)	1,141	—	(36)	(354)	6,657
Sales and other operating revenue	8,883	12,914	78,500	130,406	11,995	16,633	4,858	12,473	30	276,692
Intersegment revenue	16,692	33,405	16,735	25,097	5,993	4,082	2,193	749	227	—
Depreciation and depletion expense	6,831	9,918	700	1,036	505	450	97	195	875	20,607
Interest revenue	—	—	—	—	—	—	—	—	33	33
Interest expense	58	36	1	6	—	1	—	1	844	947
Income tax expense (benefit)	1,116	4,871	156	(165)	1,235	684	464	329	(1,054)	7,636
Additions to property, plant and equipment	3,308	5,308	979	874	538	712	28	136	658	12,541
Investments in equity companies	4,999	18,544	353	972	3,019	2,490	—	1,185	(337)	31,225
Total assets	67,294	141,978	26,932	37,698	16,695	14,555	2,878	8,030	22,863	338,923

Due to rounding, numbers presented may not add up precisely to the totals indicated.

112

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)	2023	2022	2021

Revenue from contracts with customers	256,455	304,758	228,968
Revenue outside the scope of ASC 606	78,242	93,917	47,724
Total	334,697	398,675	276,692

Geographic


Sales and other operating revenue (millions of dollars)	2023	2022	2021

United States	127,374	149,225	104,236
Non-U.S.	207,323	249,450	172,456
Total	334,697	398,675	276,692

Significant non-U.S. revenue sources include: (1)
Canada	28,994	32,970	22,166
United Kingdom	23,372	33,988	14,759
Singapore	15,331	19,029	15,031
France	14,803	17,727	13,236
Australia	9,883	11,316	7,646
Belgium	9,840	11,279	9,153
Germany	9,297	10,190	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)	December 31,
	2023	2022	2021

United States	95,792	90,051	90,412
Non-U.S.	119,148	114,641	126,140
Total	214,940	204,692	216,552

Significant non-U.S. long-lived assets include:
Canada	31,682	31,106	34,907
Singapore	12,490	11,972	11,969
Australia	11,212	11,372	12,988
Guyana	9,689	6,766	4,892
Kazakhstan	7,728	8,172	8,463
Papua New Guinea	7,433	7,338	7,534
United Arab Emirates	5,480	5,448	5,392
Brazil	4,203	3,649	4,337
China	3,669	2,350	984
Nigeria	3,319	4,090	5,235
Russia	—	—	4,055

113

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	1,987	12,111	14,098	696	15,071	15,767	236	6,948	7,184
Deferred - net	463	481	944	4,122	(539)	3,583	870	(914)	(44)
U.S. tax on non-U.S. operations	315	—	315	65	—	65	26	—	26
Total federal and non-U.S.	2,765	12,592	15,357	4,883	14,532	19,415	1,132	6,034	7,166
State	72	—	72	761	—	761	470	—	470
Total income tax expense (benefit)	2,837	12,592	15,429	5,644	14,532	20,176	1,602	6,034	7,636

All other taxes and duties
Other taxes and duties	3,871	25,140	29,011	4,087	23,832	27,919	3,731	26,508	30,239
Included in production and manufacturing expenses	1,961	726	2,687	2,204	862	3,066	1,589	674	2,263
Included in SG&A expenses	183	310	493	151	319	470	170	283	453
Total other taxes and duties	6,015	26,176	32,191	6,442	25,013	31,455	5,490	27,465	32,955
Total	8,852	38,768	47,620	12,086	39,545	51,631	7,092	33,499	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	14,786	28,281	9,478
Non-U.S.	37,997	49,472	21,756
Total	52,783	77,753	31,234
Theoretical tax	11,084	16,328	6,559
Effect of equity method of accounting	(1,341)	(2,407)	(1,398)
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)	5,888	6,423	2,809
State taxes, net of federal tax benefit	57	601	371

Other	(259)	(769)	(705)
Total income tax expense (credit)	15,429	20,176	7,636

Effective tax rate calculation
Income tax expense (credit)	15,429	20,176	7,636
ExxonMobil share of equity company income taxes	3,058	7,594	2,756
Total income tax expense (credit)	18,487	27,770	10,392
Net income (loss) including noncontrolling interests	37,354	57,577	23,598
Total income (loss) before taxes	55,841	85,347	33,990

Effective income tax rate	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)	2023	2022

Property, plant and equipment	26,627	25,607
Other liabilities	7,534	7,401
Total deferred tax liabilities	34,161	33,008

Pension and other postretirement benefits	(1,777)	(1,754)
Asset retirement obligations	(3,532)	(3,045)
Tax loss carryforwards	(4,317)	(4,862)
Other assets	(6,361)	(6,948)
Total deferred tax assets	(15,987)	(16,609)

Asset valuation allowances	2,641	2,650
Net deferred tax liabilities	20,815	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)	2023	2022

Other assets, including intangibles, net	(3,637)	(3,825)
Deferred income tax liabilities	24,452	22,874
Net deferred tax liabilities	20,815	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)	2023	2022	2021

Balance at January 1	3,398	9,130	8,764
Additions based on current year's tax positions	350	539	358
Additions for prior years' tax positions	400	294	100
Reductions for prior years' tax positions	(38)	(6,243)	(79)
Reductions due to lapse of the statute of limitations	(25)	(16)	(2)
Settlements with tax authorities	(153)	(277)	(11)
Foreign exchange effects/other	3	(29)	—
Balance at December 31	3,935	3,398	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	2010	—	2023
Belgium	2020	—	2023
Canada	2001	—	2023
Kazakhstan	2015	—	2023
Nigeria	2016	—	2023
Papua New Guinea	2008	—	2023
United Arab Emirates	2022	—	2023
United States	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			0.4
Property, plant & equipment			6.4
Other assets			0.2
Total assets			7.0

Current liabilities			0.3
Long-term liabilities			1.6
Total liabilities			1.9

Net assets acquired			5.1

Inputs for the assumptions used in the income approach to value property, plant and equipment included estimates for pipeline tariff rates, pipeline throughput volumes, commodity prices, future oil and gas production profiles, operating expenses, and a risk-adjusted discount rate.

The Denbury acquisition resulted in an immaterial amount of goodwill. Revenues and earnings arising from Denbury's operations are immaterial in 2023 for pro forma disclosure purposes.

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.


Results of Operations (millions of dollars)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

2023
Consolidated Subsidiaries
Sales to third parties	5,098	4,027	1,345	298	2,490	4,588	17,846
Transfers	13,378	11,474	47	6,355	10,779	600	42,633
Revenue	18,476	15,501	1,392	6,653	13,269	5,188	60,479

Production costs excluding taxes	4,164	4,943	623	1,710	1,146	511	13,097
Exploration expenses	44	505	25	124	18	35	751
Depreciation and depletion	8,479	2,866	96	1,561	1,519	755	15,276
Taxes other than income	1,701	117	48	516	1,936	358	4,676
Related income tax	703	1,196	315	1,299	6,498	1,078	11,089
Results of producing activities for consolidated subsidiaries	3,385	5,874	285	1,443	2,152	2,451	15,590

Equity Companies
Sales to third parties	182	—	1,211	214	14,653	—	16,260
Transfers	83	—	29	—	232	—	344
Revenue	265	—	1,240	214	14,885	—	16,604
Production costs excluding taxes	239	—	419	39	714	—	1,411
Exploration expenses	—	—	—	—	—	—	—
Depreciation and depletion	58	—	27	42	605	—	732
Taxes other than income	12	—	27	—	5,049	—	5,088
Related income tax	—	—	202	30	2,904	—	3,136
Results of producing activities for equity companies	(44)	—	565	103	5,613	—	6,237

Total results of operations	3,341	5,874	850	1,546	7,765	2,451	21,827

120


Results of Operations (millions of dollars)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

2022
Consolidated Subsidiaries
Sales to third parties	8,801	4,401	2,388	463	2,710	6,222	24,985
Transfers	17,020	12,568	60	8,634	12,274	996	51,552
Revenue	25,821	16,969	2,448	9,097	14,984	7,218	76,537
Production costs excluding taxes	3,965	5,519	464	1,965	1,492	513	13,918
Exploration expenses	18	698	28	168	51	62	1,025
Depreciation and depletion	5,472	3,700	193	2,293	5,672	829	18,159
Taxes other than income	2,314	120	140	729	2,312	689	6,304
Related income tax	3,294	1,112	1,048	2,004	6,008	1,549	15,015
Results of producing activities for consolidated subsidiaries	10,758	5,820	575	1,938	(551)	3,576	22,116

Equity Companies
Sales to third parties	820	—	2,791	10	20,750	—	24,371
Transfers	640	—	51	—	316	—	1,007
Revenue	1,460	—	2,842	10	21,066	—	25,378
Production costs excluding taxes	667	—	607	21	379	—	1,674
Exploration expenses	—	—	1	—	—	—	1
Depreciation and depletion	280	—	48	1	717	—	1,046
Taxes other than income	37	—	232	—	6,857	—	7,126
Related income tax	—	—	1,413	(2)	4,559	—	5,970
Results of producing activities for equity companies	476	—	541	(10)	8,554	—	9,561

Total results of operations	11,234	5,820	1,116	1,928	8,003	3,576	31,677

2021
Consolidated Subsidiaries
Sales to third parties	5,797	2,480	1,628	253	2,110	3,182	15,450
Transfers	10,938	8,492	412	6,087	8,829	812	35,570
Revenue	16,735	10,972	2,040	6,340	10,939	3,994	51,020
Production costs excluding taxes	3,436	4,867	754	1,759	1,471	481	12,768
Exploration expenses	19	464	26	359	146	40	1,054
Depreciation and depletion	6,185	2,690	408	2,799	1,965	1,002	15,049
Taxes other than income	1,367	113	11	490	1,258	423	3,662
Related income tax	1,276	55	235	311	3,858	610	6,345
Results of producing activities for consolidated subsidiaries	4,452	2,783	606	622	2,241	1,438	12,142

Equity Companies
Sales to third parties	620	—	1,332	—	12,239	—	14,191
Transfers	479	—	33	—	151	—	663
Revenue	1,099	—	1,365	—	12,390	—	14,854
Production costs excluding taxes	538	—	1,065	11	413	—	2,027
Exploration expenses	—	—	2	—	—	—	2
Depreciation and depletion	509	—	194	—	611	—	1,314
Taxes other than income	33	—	48	—	3,749	—	3,830
Related income tax	—	—	13	3	2,652	—	2,668
Results of producing activities for equity companies	19	—	43	(14)	4,965	—	5,013

Total results of operations	4,471	2,783	649	608	7,206	1,438	17,155

121

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)		United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

As of December 31, 2023
Consolidated Subsidiaries
Property (acreage) costs	– Proved	14,758	3,420	7	1,512	3,013	699	23,409
	– Unproved	11,220	3,035	37	122	5	2,660	17,079
Total property costs		25,978	6,455	44	1,634	3,018	3,359	40,488
Producing assets		100,167	53,019	12,676	52,243	45,260	15,306	278,671
Incomplete construction		5,460	9,712	172	1,393	3,178	2,402	22,317
Total capitalized costs		131,605	69,186	12,892	55,270	51,456	21,067	341,476
Accumulated depreciation and depletion		72,548	27,224	12,289	48,751	32,764	10,424	204,000
Net capitalized costs for consolidated subsidiaries		59,057	41,962	603	6,519	18,692	10,643	137,476

Equity Companies
Property (acreage) costs	– Proved	—	—	4	309	—	—	313
	– Unproved	—	—	—	3,111	—	—	3,111
Total property costs		—	—	4	3,420	—	—	3,424
Producing assets		1,332	—	5,493	288	10,153	—	17,266
Incomplete construction		1	—	11	550	13,083	—	13,645
Total capitalized costs		1,333	—	5,508	4,258	23,236	—	34,335
Accumulated depreciation and depletion		789	—	5,177	42	7,768	—	13,776
Net capitalized costs for equity companies		544	—	331	4,216	15,468	—	20,559

As of December 31, 2022
Consolidated Subsidiaries
Property (acreage) costs	– Proved	15,547	3,427	9	1,510	3,023	695	24,211
	– Unproved	13,797	3,011	37	119	5	2,659	19,628
Total property costs		29,344	6,438	46	1,629	3,028	3,354	43,839
Producing assets		96,209	49,923	12,156	53,164	45,405	14,296	271,153
Incomplete construction		4,169	7,774	172	1,404	3,043	2,276	18,838
Total capitalized costs		129,722	64,135	12,374	56,197	51,476	19,926	333,830
Accumulated depreciation and depletion		72,686	25,852	11,752	48,606	32,025	9,548	200,469
Net capitalized costs for consolidated subsidiaries		57,036	38,283	622	7,591	19,451	10,378	133,361

Equity Companies
Property (acreage) costs	– Proved	99	—	3	309	—	—	411
	– Unproved	2	—	—	3,111	—	—	3,113
Total property costs		101	—	3	3,420	—	—	3,524
Producing assets		6,882	—	5,243	281	10,177	—	22,583
Incomplete construction		160	—	35	550	11,709	—	12,454
Total capitalized costs		7,143	—	5,281	4,251	21,886	—	38,561
Accumulated depreciation and depletion		4,512	—	4,934	—	7,171	—	16,617
Net capitalized costs for equity companies		2,631	—	347	4,251	14,715	—	21,944

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)		United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

During 2023
Consolidated Subsidiaries
Property acquisition costs	– Proved	2,456	—	—	2	—	—	2,458
	– Unproved	171	—	—	6	—	—	177
Exploration costs		54	693	23	117	18	35	940
Development costs		8,978	5,914	55	562	822	1,046	17,377
Total costs incurred for consolidated subsidiaries		11,659	6,607	78	687	840	1,081	20,952

Equity Companies
Property acquisition costs	– Proved	—	—	—	—	—	—	—
	– Unproved	—	—	—	—	—	—	—
Exploration costs		—	—	—	—	—	—	—
Development costs		10	—	5	7	1,488	—	1,510
Total costs incurred for equity companies		10	—	5	7	1,488	—	1,510

During 2022
Consolidated Subsidiaries
Property acquisition costs	– Proved	10	11	—	151	32	—	204
	– Unproved	19	—	—	—	—	7	26
Exploration costs		27	736	71	145	38	62	1,079
Development costs		5,821	4,759	161	533	1,490	440	13,204
Total costs incurred for consolidated subsidiaries		5,877	5,506	232	829	1,560	509	14,513

Equity Companies
Property acquisition costs	– Proved	—	—	—	—	—	—	—
	– Unproved	—	—	—	—	—	—	—
Exploration costs		—	—	1	—	—	—	1
Development costs		95	—	13	22	1,638	—	1,768
Total costs incurred for equity companies		95	—	14	22	1,638	—	1,769

During 2021
Consolidated Subsidiaries
Property acquisition costs	– Proved	37	—	—	90	15	—	142
	– Unproved	78	575	—	—	—	35	688
Exploration costs		19	903	46	185	47	40	1,240
Development costs		3,352	2,619	207	389	805	435	7,807
Total costs incurred for consolidated subsidiaries		3,486	4,097	253	664	867	510	9,877

Equity Companies
Property acquisition costs	– Proved	—	—	—	—	—	—	—
	– Unproved	—	—	—	—	—	—	—
Exploration costs		—	—	1	—	—	—	1
Development costs		8	—	20	88	1,334	—	1,450
Total costs incurred for equity companies		8	—	21	88	1,334	—	1,451

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	Bitumen	Synthetic Oil	Total
(millions of barrels)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total	Worldwide	Canada/ Other Americas	Canada/ Other Americas

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2021	1,959	497	22	356	3,150	74	6,058	1,054	81	444	7,637
Revisions	47	(2)	15	67	36	10	173	4	2,944	17	3,138
Improved recovery	—	—	—	—	—	—	—	—	2	—	2
Purchases	5	—	—	—	—	—	5	1	—	—	6
Sales	(27)	(8)	(28)	—	—	—	(63)	(20)	—	—	(83)
Extensions/discoveries	499	329	—	—	—	—	828	183	—	—	1,011
Production	(176)	(47)	(6)	(88)	(149)	(10)	(476)	(86)	(133)	(23)	(718)
December 31, 2021	2,307	769	3	335	3,037	74	6,525	1,136	2,894	438	10,993
Attributable to noncontrolling interests		9						1	674	133

Proportional interest in proved reserves of equity companies
January 1, 2021	131	—	9	6	825	—	971	277	—	—	1,248
Revisions	38	—	2	(1)	(8)	—	31	15	—	—	46
Improved recovery	—	—	—	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	—	—	—	—	—	—	—
Sales	—	—	—	—	—	—	—	—	—	—	—
Extensions/discoveries	2	—	—	—	—	—	2	—	—	—	2
Production	(16)	—	(1)	—	(76)	—	(93)	(22)	—	—	(115)
December 31, 2021	155	—	10	5	741	—	911	270	—	—	1,181
Total liquids proved reserves at December 31, 2021	2,462	769	13	340	3,778	74	7,436	1,406	2,894	438	12,174

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2022	2,307	769	3	335	3,037	74	6,525	1,136	2,894	438	10,993
Revisions (1)	(375)	52	3	38	(95)	2	(375)	(85)	(422)	(62)	(944)
Improved recovery	—	—	—	—	—	—	—	—	—	—	—
Purchases	1	—	—	—	—	—	1	—	—	—	1
Sales	(3)	(12)	—	(17)	—	—	(32)	(20)	—	—	(52)
Extensions/discoveries	465	208	—	—	—	—	673	235	67	—	975
Production	(191)	(72)	(1)	(85)	(148)	(10)	(507)	(90)	(119)	(23)	(739)
December 31, 2022	2,204	945	5	271	2,794	66	6,285	1,176	2,420	353	10,234
Attributable to noncontrolling interests		14							554	107

Proportional interest in proved reserves of equity companies
January 1, 2022	155	—	10	5	741	—	911	270	—	—	1,181
Revisions	(21)	—	(7)	—	(17)	—	(45)	(10)	—	—	(55)
Improved recovery	—	—	—	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	110	—	110	117	—	—	227
Sales	—	—	—	—	—	—	—	—	—	—	—
Extensions/discoveries	—	—	—	—	—	—	—	—	—	—	—
Production	(15)	—	(1)	—	(78)	—	(94)	(22)	—	—	(116)
December 31, 2022	119	—	2	5	756	—	882	355	—	—	1,237
Total liquids proved reserves at December 31, 2022	2,323	945	7	276	3,550	66	7,167	1,531	2,420	353	11,471
(1) Includes (118) million barrels in Russia which were expropriated. See Note 2: Russia.

125


Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
	Crude Oil							Natural Gas Liquids	Bitumen	Synthetic Oil	Total
(millions of barrels)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total	Worldwide	Canada/ Other Americas	Canada/ Other Americas

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2023	2,204	945	5	271	2,794	66	6,285	1,176	2,420	353	10,234
Revisions	(398)	32	—	31	30	3	(302)	(110)	123	26	(263)
Improved recovery	—	—	—	—	—	—	—	—	—	—	—
Purchases	156	—	—	—	—	—	156	2	—	—	158
Sales	(12)	—	—	—	(4)	—	(16)	(5)	—	—	(21)
Extensions/discoveries	355	105	—	—	—	—	460	272	—	—	732
Production	(203)	(88)	(1)	(78)	(153)	(8)	(531)	(99)	(129)	(25)	(784)
December 31, 2023	2,102	994	4	224	2,667	61	6,052	1,236	2,414	354	10,056
Attributable to noncontrolling interests		1							551	108

Proportional interest in proved reserves of equity companies
January 1, 2023	119	—	2	5	756	—	882	355	—	—	1,237
Revisions	—	—	1	—	103	—	104	1	—	—	105
Improved recovery	—	—	—	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	—	—	—	—	—	—	—
Sales	(108)	—	—	—	—	—	(108)	(1)	—	—	(109)
Extensions/discoveries	—	—	—	—	—	—	—	—	—	—	—
Production	(4)	—	—	—	(79)	—	(83)	(22)	—	—	(105)
December 31, 2023	7	—	3	5	780	—	795	333	—	—	1,128
Total liquids proved reserves at December 31, 2023	2,109	994	7	229	3,447	61	6,847	1,569	2,414	354	11,184

126


Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
	Crude Oil and Natural Gas Liquids								Bitumen	Synthetic Oil	Total
(millions of barrels)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total		Canada/ Other Americas	Canada/ Other Americas

As of December 31, 2021
Proved developed reserves
Consolidated subsidiaries	1,663	268	3	330	2,154	63	4,481		2,635	326	7,442
Equity companies	133	—	10	—	474	—	617		—	—	617
Proved undeveloped reserves
Consolidated subsidiaries	1,621	508	—	31	988	32	3,180		259	112	3,551
Equity companies	28	—	—	5	531	—	564		—	—	564
Total liquids proved reserves at December 31, 2021	3,445	776	13	366	4,147	95	8,842		2,894	438	12,174

As of December 31, 2022
Proved developed reserves
Consolidated subsidiaries	1,688	378	5	259	2,067	50	4,447		2,288	248	6,983
Equity companies	126	—	2	5	360	—	493		—	—	493
Proved undeveloped reserves
Consolidated subsidiaries	1,568	568	—	35	813	30	3,014		132	105	3,251
Equity companies	—	—	—	—	744	—	744		—	—	744
Total liquids proved reserves at December 31, 2022	3,382	946	7	299	3,984	80	8,698		2,420	353	11,471

As of December 31, 2023
Proved developed reserves
Consolidated subsidiaries	1,735	433	4	217	1,996	45	4,430		2,307	242	6,979
Equity companies	11	—	3	5	438	—	457		—	—	457
Proved undeveloped reserves
Consolidated subsidiaries	1,498	561	—	20	751	28	2,858		107	112	3,077
Equity companies	—	—	—	—	671	—	671		—	—	671
Total liquids proved reserves at December 31, 2023	3,244	994	7	242	3,856	73	8,416	(1)	2,414	354	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) (millions of oil-equivalent barrels)
	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2021	13,439	561	441	320	4,309	6,134	25,204	11,837
Revisions	1,432	305	210	39	(276)	712	2,422	3,542
Improved recovery	—	—	—	—	—	—	—	2
Purchases	3	—	—	—	—	—	3	6
Sales	(164)	(18)	(120)	—	—	—	(302)	(134)
Extensions/discoveries	1,381	163	—	—	—	—	1,544	1,269
Production	(1,103)	(92)	(148)	(42)	(340)	(483)	(2,208)	(1,086)
December 31, 2021	14,988	919	383	317	3,693	6,363	26,663	15,436
Attributable to noncontrolling interests		124

Proportional interest in proved reserves of equity companies
January 1, 2021	102	—	360	917	11,377	—	12,756	3,374
Revisions	44	—	206	(111)	(236)	—	(97)	30
Improved recovery	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	—	—	—	—
Sales	—	—	—	—	—	—	—	—
Extensions/discoveries	5	—	—	—	—	—	5	3
Production	(11)	—	(158)	—	(983)	—	(1,152)	(307)
December 31, 2021	140	—	408	806	10,158	—	11,512	3,100
Total proved reserves at December 31, 2021	15,128	919	791	1,123	13,851	6,363	38,175	18,536

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2022	14,988	919	383	317	3,693	6,363	26,663	15,436
Revisions (2)	(990)	(38)	149	49	(307)	187	(950)	(1,102)
Improved recovery	—	—	—	—	—	—	—	—
Purchases	2	—	—	—	—	—	2	1
Sales	(1,551)	(272)	—	(1)	—	—	(1,824)	(356)
Extensions/discoveries	2,232	175	—	—	—	—	2,407	1,376
Production	(1,036)	(76)	(119)	(53)	(325)	(542)	(2,151)	(1,097)
December 31, 2022	13,645	708	413	312	3,061	6,008	24,147	14,258
Attributable to noncontrolling interests		77

Proportional interest in proved reserves of equity companies
January 1, 2022	140	—	408	806	10,158	—	11,512	3,100
Revisions	(3)	—	104	(132)	29	—	(2)	(55)
Improved recovery	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	3,101	—	3,101	744
Sales	—	—	—	—	—	—	—	—
Extensions/discoveries	—	—	—	—	—	—	—	—
Production	(10)	—	(132)	(11)	(979)	—	(1,132)	(305)
December 31, 2022	127	—	380	663	12,309	—	13,479	3,484
Total proved reserves at December 31, 2022	13,772	708	793	975	15,370	6,008	37,626	17,742

(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. (2) Includes (199) billion cubic feet of natural gas and (152) million total oil-equivalent barrels in Russia which were expropriated. See Note 2: Russia.

128


Natural Gas and Oil-Equivalent Proved Reserves (continued)
	Natural Gas (billions of cubic feet)							Oil-Equivalent Total All Products (1) (millions of oil-equivalent barrels)
	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2023	13,645	708	413	312	3,061	6,008	24,147	14,258
Revisions	(1,945)	(201)	(3)	(49)	121	339	(1,738)	(553)
Improved recovery	—	—	—	—	—	—	—	—
Purchases	7	—	—	—	—	—	7	159
Sales	(417)	(1)	—	—	(9)	—	(427)	(92)
Extensions/discoveries	1,930	67	—	—	—	—	1,997	1,065
Production	(957)	(53)	(103)	(43)	(379)	(489)	(2,024)	(1,121)
December 31, 2023	12,263	520	307	220	2,794	5,858	21,962	13,716
Attributable to noncontrolling interests		26

Proportional interest in proved reserves of equity companies
January 1, 2023	127	—	380	663	12,309	—	13,479	3,484
Revisions	(27)	—	18	157	(32)	—	116	124
Improved recovery	—	—	—	—	—	—	—	—
Purchases	—	—	—	—	—	—	—	—
Sales	(35)	—	—	—	—	—	(35)	(115)
Extensions/discoveries	—	—	—	—	—	—	—	—
Production	(8)	—	(54)	(40)	(956)	—	(1,058)	(281)
December 31, 2023	57	—	344	780	11,321	—	12,502	3,212
Total proved reserves at December 31, 2023	12,320	520	651	1,000	14,115	5,858	34,464	16,928

(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.

129


Natural Gas and Oil-Equivalent Proved Reserves (continued)
	Natural Gas (billions of cubic feet)							Oil-Equivalent Total All Products (1) (millions of oil-equivalent barrels)
	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total

As of December 31, 2021
Proved developed reserves
Consolidated subsidiaries	11,287	574	377	315	2,527	3,513	18,593	10,540
Equity companies	117	—	339	—	6,017	—	6,473	1,696
Proved undeveloped reserves
Consolidated subsidiaries	3,701	345	6	2	1,166	2,850	8,070	4,896
Equity companies	23	—	69	806	4,141	—	5,039	1,404
Total proved reserves at December 31, 2021	15,128	919	791	1,123	13,851	6,363	38,175	18,536

As of December 31, 2022
Proved developed reserves
Consolidated subsidiaries	9,577	371	408	307	2,037	3,162	15,862	9,627
Equity companies	127	—	326	663	5,020	—	6,136	1,516
Proved undeveloped reserves
Consolidated subsidiaries	4,068	337	5	5	1,024	2,846	8,285	4,631
Equity companies	—	—	54	—	7,289	—	7,343	1,968
Total proved reserves at December 31, 2022	13,772	708	793	975	15,370	6,008	37,626	17,742

As of December 31, 2023
Proved developed reserves
Consolidated subsidiaries	8,138	329	307	220	1,935	3,163	14,092	9,327
Equity companies	57	—	290	780	4,223	—	5,350	1,349
Proved undeveloped reserves
Consolidated subsidiaries	4,125	191	—	—	859	2,695	7,870	4,389
Equity companies	—	—	54	—	7,098	—	7,152	1,863
Total proved reserves at December 31, 2023	12,320	520	651	1,000	14,115	5,858	34,464	16,928

(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)	United States	Canada/Other Americas (1)	Europe	Africa	Asia	Australia/ Oceania	Total

As of December 31, 2021
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas	217,023	209,711	4,322	24,812	211,255	69,015	736,138
Future production costs	63,464	111,468	1,142	7,700	55,241	14,880	253,895
Future development costs	29,941	31,736	2,113	5,921	14,519	7,286	91,516
Future income tax expenses	24,770	12,004	451	4,319	107,577	13,038	162,159
Future net cash flows	98,848	54,503	616	6,872	33,918	33,811	228,568
Effect of discounting net cash flows at 10%	50,524	25,793	(502)	739	17,383	18,751	112,688
Discounted future net cash flows	48,324	28,710	1,118	6,133	16,535	15,060	115,880

Equity Companies
Future cash inflows from sales of oil and gas	10,607	—	5,889	4,553	146,845	—	167,894
Future production costs	5,005	—	785	261	49,810	—	55,861
Future development costs	2,340	—	1,137	62	8,317	—	11,856
Future income tax expenses	—	—	1,793	1,168	29,463	—	32,424
Future net cash flows	3,262	—	2,174	3,062	59,255	—	67,753
Effect of discounting net cash flows at 10%	1,553	—	683	1,868	25,710	—	29,814
Discounted future net cash flows	1,709	—	1,491	1,194	33,545	—	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)	United States	Canada/Other Americas (1)	Europe	Africa	Asia	Australia/ Oceania	Total

As of December 31, 2022
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas	316,486	284,643	11,806	30,040	271,732	114,959	1,029,666
Future production costs	78,939	113,264	2,627	7,489	63,705	21,972	287,996
Future development costs	31,960	34,968	2,016	6,143	9,241	7,089	91,417
Future income tax expenses	45,278	31,603	3,164	8,300	156,595	24,955	269,895
Future net cash flows	160,309	104,808	3,999	8,108	42,191	60,943	380,358
Effect of discounting net cash flows at 10%	83,711	49,861	187	322	21,772	34,896	190,749
Discounted future net cash flows	76,598	54,947	3,812	7,786	20,419	26,047	189,609

Equity Companies
Future cash inflows from sales of oil and gas	12,312	—	13,706	7,194	261,409	—	294,621
Future production costs	5,379	—	1,981	266	96,788	—	104,414
Future development costs	1,773	—	895	60	7,275	—	10,003
Future income tax expenses	—	—	5,262	1,965	51,838	—	59,065
Future net cash flows	5,160	—	5,568	4,903	105,508	—	121,139
Effect of discounting net cash flows at 10%	2,236	—	2,234	2,694	44,728	—	51,892
Discounted future net cash flows	2,924	—	3,334	2,209	60,780	—	69,247

Total consolidated and equity interests in standardized measure of discounted future net cash flows	79,522	54,947	7,146	9,995	81,199	26,047	258,856

As of December 31, 2023
Consolidated Subsidiaries
Future cash inflows from sales of oil and gas	213,623	227,365	3,918	19,282	221,822	63,204	749,214
Future production costs	68,753	113,875	1,611	5,025	52,672	13,971	255,907
Future development costs	37,784	38,436	1,881	4,466	11,926	6,393	100,886
Future income tax expenses	14,270	15,973	509	4,337	121,751	12,119	168,959
Future net cash flows	92,816	59,081	(83)	5,454	35,473	30,721	223,462
Effect of discounting net cash flows at 10%	49,199	23,471	(762)	402	18,537	16,215	107,062
Discounted future net cash flows	43,617	35,610	679	5,052	16,936	14,506	116,400

Equity Companies
Future cash inflows from sales of oil and gas	818	—	5,101	4,393	158,643	—	168,955
Future production costs	503	—	982	233	73,496	—	75,214
Future development costs	75	—	697	100	5,452	—	6,324
Future income tax expenses	—	—	1,539	1,120	24,374	—	27,033
Future net cash flows	240	—	1,883	2,940	55,321	—	60,384
Effect of discounting net cash flows at 10%	76	—	672	1,635	20,135	—	22,518
Discounted future net cash flows	164	—	1,211	1,305	35,186	—	37,866

Total consolidated and equity interests in standardized measure of discounted future net cash flows	43,781	35,610	1,890	6,357	52,122	14,506	154,266

(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $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)	2021
	Consolidated Subsidiaries	Share of Equity Method Investees	Total Consolidated and Equity Interests

Discounted future net cash flows as of December 31, 2020	26,554	8,441	34,995

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs	11,922	22	11,944
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	(35,813)	(9,948)	(45,761)
Development costs incurred during the year	7,033	1,563	8,596
Net change in prices, lifting and development costs	118,946	47,434	166,380
Revisions of previous reserves estimates	27,126	2,507	29,633
Accretion of discount	3,762	1,201	4,963
Net change in income taxes	(43,650)	(13,281)	(56,931)
Total change in the standardized measure during the year	89,326	29,498	118,824

Discounted future net cash flows as of December 31, 2021	115,880	37,939	153,819


Consolidated and Equity Interests (millions of dollars)	2022
	Consolidated Subsidiaries	Share of Equity Method Investees	Total Consolidated and Equity Interests

Discounted future net cash flows as of December 31, 2021	115,880	37,939	153,819

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs	18,592	3,008	21,600
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs	(57,344)	(17,037)	(74,381)
Development costs incurred during the year	11,834	1,849	13,683
Net change in prices, lifting and development costs	139,844	51,094	190,938
Revisions of previous reserves estimates	(1,985)	2,140	155
Accretion of discount	14,655	4,938	19,593
Net change in income taxes	(51,867)	(14,684)	(66,551)
Total change in the standardized measure during the year	73,729	31,308	105,037

Discounted future net cash flows as of December 31, 2022	189,609	69,247	258,856


Consolidated and Equity Interests (millions of dollars)	2023
	Consolidated Subsidiaries	Share of Equity Method Investees	Total Consolidated and Equity Interests

Discounted future net cash flows as of December 31, 2022	189,609	69,247	258,856

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs	5,658	(1,701)	3,957
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs	(43,836)	(10,218)	(54,054)
Development costs incurred during the year	15,343	1,502	16,845
Net change in prices, lifting and development costs	(120,924)	(51,923)	(172,847)
Revisions of previous reserves estimates	4,953	5,096	10,049
Accretion of discount	23,006	8,962	31,968
Net change in income taxes	42,591	16,901	59,492
Total change in the standardized measure during the year	(73,209)	(31,381)	(104,590)

Discounted future net cash flows as of December 31, 2023	116,400	37,866	154,266

133

INDEX TO EXHIBITS


Exhibit			Description

2.1			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). **

3(i)			Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015).

3(ii)			By-Laws, as amended effective October 25, 2022 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of October 31, 2022).

4(vi)			Description of ExxonMobil Capital Stock (incorporated by reference to Exhibit 4(vi) to the Registrant's Annual Report on Form 10-K for 2019).

10(iii)(a.1)			2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2017).*

10(iii)(a.2)			Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2016).*

10(iii)(a.3)			Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.*

10(iii)(b.1)			Short Term Incentive Program, as amended.*

10(iii)(b.2)			Earnings Bonus Unit instrument (incorporated by reference to Exhibit 10(iii)(b.2) to the Registrant's Annual Report on Form 10-K for 2019).*

10(iii)(b.3)			Amendment of 2018 and 2019 Earnings Bonus Unit instruments, effective November 23, 2021 (incorporated by reference to Exhibit 99.1 to the Registrant's Report on Form 8-K of November 30, 2021).*

10(iii)(c.1)			ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant's Annual Report on Form 10-K for 2022).*

10(iii)(c.2)			ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant's Annual Report on Form 10-K for 2022).*

10(iii)(c.3)			ExxonMobil Additional Payments Plan.*

10(iii)(d)			ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2016).*

10(iii)(f.1)			2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2018).*

10(iii)(f.2)			Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Annual Report on Form 10-K for 2016).*

10(iii)(f.3)			Form of restricted stock grant letter for non-employee directors.*

10(iii)(f.4)			Standing resolution for non-employee director cash fees dated March 1, 2020 (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).*

10(iii)(g)			Aircraft Time Share Agreement dated as of August 29, 2023, between Exxon Mobil Corporation and Darren W. Woods (incorporated by reference to Exhibit 10(iii)(g) to the Registrant’s Report on Form 10-Q for the quarter ended October 31, 2023).*

14			Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2017).

21			Subsidiaries of the registrant.

23			Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31.1			Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.



31.2			Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Financial Officer.

31.3			Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.

32.1			Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.

32.2			Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Financial Officer.

32.3			Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.

97			Policy Relating to Recovery of Erroneously Awarded Compensation.

101			Interactive data files (formatted as Inline XBRL).

104			Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101).

* Management contract or compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K. ** 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.

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SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	EXXON MOBIL CORPORATION

	By:	/s/ DARREN W. WOODS
Dated February 28, 2024		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

/s/ MICHAEL J. ANGELAKIS

/s/ JOSEPH L. HOOLEY

Darren W. Woods, Chairman of the Board

Michael J. Angelakis

Joseph L. Hooley

/s/ SUSAN K. AVERY

/s/ STEVEN A. KANDARIAN

Principal Financial Officer

Susan K. Avery

Steven A. Kandarian

/s/ KATHRYN A. MIKELLS

/s/ ANGELA F. BRALY

/s/ ALEXANDER A. KARSNER

Kathryn A. Mikells, Senior Vice President and Chief Financial Officer

Angela F. Braly

Alexander A. Karsner

/s/ GREGORY J. GOFF

/s/ LAWRENCE W. KELLNER

Principal Accounting Officer

Gregory J. Goff

Lawrence W. Kellner

/s/ LEN M. FOX

/s/ JOHN D. HARRIS II

/s/ DINA POWELL MCCORMICK

Len M. Fox, Vice President
and Controller

John D. Harris II

Dina Powell McCormick

/s/ KAISA H. HIETALA

/s/ JEFFREY W. UBBEN

Kaisa H. Hietala

Jeffrey W. Ubben

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