EDGAR 10-K Filing

Company CIK: 34088
Filing Year: 2024
Filename: 34088_10-K_2024_0000034088-24-000018.json

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ITEM 1. BUSINESS
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.

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ITEM 1A. RISK FACTORS
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
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
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
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
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

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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.

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ITEM 9B. OTHER INFORMATION
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.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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”.

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ITEM 11. EXECUTIVE COMPENSATION
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.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.