EDGAR 10-K Filing

Company CIK: 34088
Filing Year: 2022
Filename: 34088_10-K_2022_0000034088-22-000011.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 and biofuels. 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.
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 business segments. ExxonMobil held over 8 thousand active patents worldwide at the end of 2021. For technology licensed to third parties, revenues totaled approximately $66 million in 2021. 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 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 35 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 63 thousand, 72 thousand, and 75 thousand at years ended 2021, 2020, and 2019, respectively. Regular employees are defined as active executive, management, professional, technical, 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. With respect to the environment, throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water, and ground, including, but not limited to, compliance with environmental regulations. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2021 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.6 billion, of which $3.4 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to increase to approximately $5.3 billion in 2022, with capital expenditures expected to account for approximately 30 percent of the total. Costs for 2023 are anticipated to be higher as the Low Carbon Solutions business matures and the Corporation progresses its emission-reduction plans.
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 certain of the company’s operations, especially in the Upstream segment, financial condition, and proved reserves. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the company’s operations, especially in the Downstream and Chemical segments.
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 credit 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.
COVID-19. The initial phase of the COVID-19 pandemic caused conditions of demand reduction and oversupply to develop rapidly and resulted in significant decreases in commodity prices and margins. ExxonMobil’s future business results, including cash flows and financing needs, will be affected by the scope and severity of current and future COVID outbreaks; actions taken by governments and others to address the pandemic and the effects of those actions on national and global economies and markets; changes in consumer behavior that affect demand for our products; and the effectiveness of the Corporation’s own responsive actions to protect the safety and well-being of our people.
Other demand-related factors. Other factors that may affect the demand for oil, gas, and petrochemicals, 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 that make wind and solar 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, and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, 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, and other local or regional market conditions. Market factors may also result in losses from commodity derivatives and other instruments we use to hedge price exposures or for trading purposes.
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, when national governments may have less need of 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 certain of its affiliates from doing business in certain countries, or restricting the kind of business that may be conducted. 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, or have not yet adopted, or may be unable to maintain, clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations 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);
•price controls;
•changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws affecting offshore drilling operations, water use, methane emissions, hydraulic fracturing, or use of new or recycled plastics);
•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 of our products, or otherwise require changes in the company's business or strategy that could result in reduced returns;
•adoption of regulations mandating efficiency standards, the use of alternative fuels or uncompetitive fuel components;
•adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information, or that could cause us to violate the non-disclosure laws of other countries; and
•government actions to cancel contracts, re-denominate 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 though litigation targeting the company or other industry participants), gain political notoriety, or obtain monetary awards from the company.
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 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. 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 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 lead in the energy transition, including the company’s announced ambition ultimately to achieve net-zero with respect to emissions from operations where ExxonMobil is the operator, carries risks that the transition, including underlying technologies, policies, and markets as discussed in more detail below, will not 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 change 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, 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 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 and taking 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 low carbon 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 and advanced biofuels, breakthrough energy efficiency processes, advanced energy-saving materials, and other technologies. The company’s efforts include both in-house research and development and collaborative efforts with leading universities as well as commercial partners involved in advanced lower-emission energy technologies. Our future results and ability to grow our LCS business 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.
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. 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 on line as scheduled and within budget.
Project and portfolio management. The long-term success of ExxonMobil’s Upstream, Downstream, and Chemical 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; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; 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 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 and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements, 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 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 control effectively our business activities, 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 air emissions, not only in response to government requirements but also to address community priorities. We employ a comprehensive 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. ExxonMobil’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions; non-technological measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness and an emphasis on resiliency including business response and recovery. 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 are also exposed to potential harm from cybersecurity events that may affect the operations of third-parties, including our partners, suppliers, service providers (including providers of cloud-hosting services for our data or applications), and customers. 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, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of engineering 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 as well as 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 lead 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, attract talent, or 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, 2, 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 2021
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. As a result of higher average prices in 2021, certain quantities of crude oil, bitumen, and natural gas that did not qualify as proved reserves in the prior year qualified as proved reserves at year-end 2021. Otherwise, no major discovery or other favorable or adverse event has occurred since December 31, 2021 that would cause a significant change in the estimated proved reserves as of that date.
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)
Proved Reserves
Developed
Consolidated Subsidiaries
United States 1,170 493 - - 11,287 3,544
Canada/Other Americas (1)
262 6 2,635 326 574 3,325
Europe 3 - - - 377 66
Africa 304 26 - - 315 382
Asia 2,096 58 - - 2,527 2,575
Australia/Oceania 45 18 - - 3,513 648
Total Consolidated 3,880 601 2,635 326 18,593 10,540
Equity Companies
United States 127 6 - - 117 153
Europe 10 - - - 339 66
Africa - - - - - -
Asia 322 152 - - 6,017 1,477
Total Equity Company 459 158 - - 6,473 1,696
Total Developed 4,339 759 2,635 326 25,066 12,236
Undeveloped
Consolidated Subsidiaries
United States 1,137 484 - - 3,701 2,238
Canada/Other Americas (1)
507 1 259 112 345 937
Europe - - - - 6 1
Africa 31 - - - 2 31
Asia 941 47 - - 1,166 1,182
Australia/Oceania 29 3 - - 2,850 507
Total Consolidated 2,645 535 259 112 8,070 4,896
Equity Companies
United States 28 - - - 23 32
Europe - - - - 69 12
Africa 5 - - - 806 139
Asia 419 112 - - 4,141 1,221
Total Equity Company 452 112 - - 5,039 1,404
Total Undeveloped 3,097 647 259 112 13,109 6,300
Total Proved Reserves 7,436 1,406 2,894 438 38,175 18,536
(1)Other Americas includes proved developed reserves of 106 million barrels of crude oil and 151 billion cubic feet of natural gas, as well as proved undeveloped reserves of 488 million barrels of crude oil and 233 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; performance of enhanced oil recovery projects; 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; 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 2021
Additions to ExxonMobil’s proved reserves in 2021 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 Manager of the Global Reserves and Resources group 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 (SPE). 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 2021, approximately 6.3 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 34 percent of the 18.5 GOEB reported in proved reserves. This compares to 5.0 GOEB of proved undeveloped reserves reported at the end of 2020. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 0.5 GOEB from proved undeveloped to proved developed reserves by year end. The largest transfers were related to development activities in the United States. During 2021, extensions and discoveries, primarily in the United States, Brazil, and Guyana, resulted in an addition of approximately 1.3 GOEB of proved undeveloped reserves, along with an increase of approximately 0.6 GOEB due to revisions primarily in Asia and Canada.
Overall, investments of $8.0 billion were made by the Corporation during 2021 to progress the development of reported proved undeveloped reserves, including $7.8 billion for oil and gas producing activities, along with additional investments for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 65 percent of the $12.3 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, Canada, Kazakhstan, the United States, and the United Arab Emirates have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, the pace of co-venturer/government funding, changes in the amount and timing of capital investments, and significant changes in crude oil and natural gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, over 80 percent are contained in the aforementioned countries. In Australia, proved undeveloped reserves are associated with future compression for the Gorgon Jansz LNG project. In Canada, proved undeveloped reserves are related to Cold Lake operations. 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.
2021 2020 2019
(thousands of barrels daily)
Crude oil and natural gas liquids production Crude Oil NGL Crude Oil NGL Crude Oil NGL
Consolidated Subsidiaries
United States 482 195 481 154 461 131
Canada/Other Americas (1)
130 3 121 5 87 4
Europe 16 3 22 5 84 21
Africa 241 7 301 11 360 12
Asia 407 21 449 23 432 22
Australia/Oceania 28 15 29 15 30 15
Total Consolidated Subsidiaries 1,304 244 1,403 213 1,454 205
Equity Companies
United States 43 1 49 1 52 2
Europe 3 - 3 - 3 -
Asia 207 60 208 62 232 62
Total Equity Companies 253 61 260 63 287 64
Total crude oil and natural gas liquids production 1,557 305 1,663 276 1,741 269
Bitumen production
Consolidated Subsidiaries
Canada/Other Americas 365 342 311
Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas 62 68 65
Total liquids production 2,289 2,349 2,386
(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States 2,724 2,668 2,756
Canada/Other Americas (1)
195 277 258
Europe 377 447 808
Africa 43 9 7
Asia 807 872 851
Australia/Oceania 1,280 1,219 1,319
Total Consolidated Subsidiaries 5,426 5,492 5,999
Equity Companies
United States 22 23 22
Europe 431 342 649
Asia 2,658 2,614 2,724
Total Equity Companies 3,111 2,979 3,395
Total natural gas production available for sale 8,537 8,471 9,394
(thousands of oil-equivalent barrels daily)
Oil-equivalent production 3,712 3,761 3,952
(1)Other Americas includes crude oil production for 2021, 2020 and 2019 of 48 thousand, 29 thousand, and 2 thousand barrels daily, respectively; and natural gas production available for sale for 2021, 2020 and 2019 of 36 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.
United
States Canada/
Other
Americas Europe Africa Asia Australia/
Oceania Total
During 2021
(dollars per unit)
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
During 2020
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 34.97 37.26 41.39 42.27 39.39 36.67 38.31
NGL, per barrel 13.83 10.34 20.11 21.32 21.37 27.92 16.05
Natural gas, per thousand cubic feet 0.98 1.56 3.13 1.24 1.49 4.34 2.01
Bitumen, per barrel - 17.71 - - - - 17.71
Synthetic oil, per barrel - 37.32 - - - - 37.32
Average production costs, per oil-equivalent barrel - total 9.82 18.40 21.22 16.67 6.50 5.35 11.57
Average production costs, per barrel - bitumen - 19.22 - - - - 19.22
Average production costs, per barrel - synthetic oil - 33.61 - - - - 33.61
Equity Companies
Average production prices
Crude oil, per barrel 39.10 - 38.95 - 35.18 - 35.97
NGL, per barrel 11.05 - - - 30.02 - 29.58
Natural gas, per thousand cubic feet 1.19 - 3.85 - 3.14 - 3.20
Average production costs, per oil-equivalent barrel - total 25.13 - 30.74 - 1.63 - 5.34
Total
Average production prices
Crude oil, per barrel 35.35 37.26 41.11 42.27 38.07 36.67 37.95
NGL, per barrel 13.80 10.34 20.11 21.32 27.65 27.92 19.16
Natural gas, per thousand cubic feet 0.98 1.56 3.44 1.24 2.72 4.34 2.43
Bitumen, per barrel - 17.71 - - - - 17.71
Synthetic oil, per barrel - 37.32 - - - - 37.32
Average production costs, per oil-equivalent barrel - total 10.55 18.40 24.76 16.73 3.91 5.35 10.21
Average production costs, per barrel - bitumen - 19.22 - - - - 19.22
Average production costs, per barrel - synthetic oil - 33.61 - - - - 33.61
United
States Canada/
Other
Americas Europe Africa Asia Australia/
Oceania Total
During 2019
(dollars per unit)
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 54.41 59.39 63.59 65.64 64.14 61.08 61.04
NGL, per barrel 18.94 16.59 30.56 41.41 24.64 30.55 22.85
Natural gas, per thousand cubic feet 1.54 1.44 4.50 1.49 2.07 6.26 3.05
Bitumen, per barrel - 36.25 - - - - 36.25
Synthetic oil, per barrel - 56.18 - - - - 56.18
Average production costs, per oil-equivalent barrel - total 12.25 23.41 13.69 17.51 7.34 6.60 13.43
Average production costs, per barrel - bitumen - 24.18 - - - - 24.18
Average production costs, per barrel - synthetic oil - 40.38 - - - - 40.38
Equity Companies
Average production prices
Crude oil, per barrel 60.95 - 58.72 - 58.74 - 59.15
NGL, per barrel 15.63 - - - 36.28 - 35.76
Natural gas, per thousand cubic feet 1.75 - 5.01 - 5.24 - 5.17
Average production costs, per oil-equivalent barrel - total 25.70 - 14.04 - 2.03 - 5.00
Total
Average production prices
Crude oil, per barrel 55.08 59.39 63.41 65.64 62.27 61.08 60.73
NGL, per barrel 18.90 16.59 30.56 41.41 33.23 30.55 25.89
Natural gas, per thousand cubic feet 1.54 1.44 4.73 1.49 4.49 6.26 3.82
Bitumen, per barrel - 36.25 - - - - 36.25
Synthetic oil, per barrel - 56.18 - - - - 56.18
Average production costs, per oil-equivalent barrel - total 12.95 23.41 13.80 17.56 4.39 6.60 11.48
Average production costs, per barrel - bitumen - 24.18 - - - - 24.18
Average production costs, per barrel - synthetic oil - 40.38 - - - - 40.38
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
2021 2020 2019
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States 1 4 3
Canada/Other Americas 5 2 6
Europe - - 1
Africa - 1 -
Asia - - -
Australia/Oceania - - 1
Total Consolidated Subsidiaries 6 7 11
Equity Companies
United States - - -
Europe - - -
Africa - - -
Asia - - -
Total Equity Companies - - -
Total productive exploratory wells drilled 6 7 11
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States 1 - -
Canada/Other Americas 3 1 1
Europe - - 1
Africa - - -
Asia - 1 -
Australia/Oceania - - 1
Total Consolidated Subsidiaries 4 2 3
Equity Companies
United States - - -
Europe - - -
Africa - - -
Asia - - -
Total Equity Companies - - -
Total dry exploratory wells drilled 4 2 3
2021 2020 2019
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States 433 412 618
Canada/Other Americas 28 36 49
Europe 1 2 3
Africa 1 2 4
Asia 4 15 12
Australia/Oceania - 4 -
Total Consolidated Subsidiaries 467 471 686
Equity Companies
United States 13 60 199
Europe 1 1 -
Africa 1 - -
Asia 5 5 9
Total Equity Companies 20 66 208
Total productive development wells drilled 487 537 894
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States 4 6 8
Canada/Other Americas - - -
Europe - - -
Africa - - 1
Asia - - -
Australia/Oceania - 1 -
Total Consolidated Subsidiaries 4 7 9
Equity Companies
United States - - -
Europe - - -
Africa - - -
Asia - - -
Total Equity Companies - - -
Total dry development wells drilled 4 7 9
Total number of net wells drilled 501 553 917
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 2021, the company’s share of net production of synthetic crude oil was about 62 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 2021, average net production at Kearl was about 251 thousand barrels per day.
During 2021, approximately 2.4 billion barrels of bitumen at Kearl were added to proved reserves primarily as a result of an improved SEC price basis versus 2020.
5. Present Activities
A. Wells Drilling
Year-End 2021
Year-End 2020
Gross Net Gross Net
Wells Drilling
Consolidated Subsidiaries
United States 1,059 588 1,206 741
Canada/Other Americas 44 33 38 29
Europe 2 1 13 6
Africa 11 2 14 3
Asia 11 3 14 4
Australia/Oceania - - - -
Total Consolidated Subsidiaries 1,127 627 1,285 783
Equity Companies
United States 12 - 3 1
Europe - - 1 1
Africa - - 6 1
Asia 2 1 2 1
Total Equity Companies 14 1 12 4
Total gross and net wells drilling 1,141 628 1,297 787
B. Review of Principal Ongoing Activities
UNITED STATES
ExxonMobil’s year-end 2021 acreage holdings totaled 10.5 million net acres, of which 0.3 million net 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 liquefied natural gas export project.
During the year, a total of 449.4 net exploration 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.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2021 was 0.3 million acres. A total of 0.8 net exploration and development wells were completed during the year.
Participation in Alaska production and development continued with a total of 1.1 net development wells completed.
CANADA / OTHER AMERICAS
Canada
Oil and Gas Operations: ExxonMobil’s year-end 2021 acreage holdings totaled 6.7 million net acres, of which 3.9 million net acres were offshore. A total of 3.7 net development wells were completed during the year.
In Situ Bitumen Operations: ExxonMobil’s year-end 2021 in situ bitumen acreage holdings totaled 0.6 million net onshore acres. A total of 12 net development wells at Cold Lake were completed during the year.
Argentina
ExxonMobil’s net acreage totaled 2.9 million acres, of which 2.6 million net acres were offshore at year-end 2021. During the year, a total of 8.1 net development wells were completed.
Brazil
ExxonMobil’s net acreage totaled 2.6 million offshore acres at year-end 2021. During the year, a total of 1.4 net exploration wells were completed. The Bacalhau Phase 1 project was funded in 2021.
Guyana
ExxonMobil’s net acreage totaled 4.6 million offshore acres at year-end 2021. During the year, a total of 11 net exploration and development wells were completed. Development activities continued on the Liza Phase 2 and Payara projects.
EUROPE
Germany
ExxonMobil’s net acreage totaled 1.6 million onshore acres at year-end 2021. During the year, a total of 0.3 net development well was completed.
Netherlands
ExxonMobil’s net interest in licenses totaled 1.4 million acres, of which 1.0 million acres were onshore at year-end 2021. During the year, a total of 0.5 net development well was completed. In 2021, the Dutch Government further reduced Groningen gas extraction. The expectation is that Groningen will cease regular production in 2022.
United Kingdom
ExxonMobil’s net interest in licenses totaled 0.1 million offshore acres at year-end 2021. During the year, a total of 0.4 net development well was completed.
AFRICA
Angola
ExxonMobil’s net acreage totaled 3.0 million acres, of which 2.9 million net acres were offshore at year-end 2021. During the year, a total of 1.1 net development wells were completed.
Chad
ExxonMobil’s net acreage totaled 46 thousand onshore acres at year-end 2021. In 2021, ExxonMobil entered into an agreement to divest its assets in Chad. The transaction is expected to close in 2022.
Equatorial Guinea
ExxonMobil’s net acreage totaled 0.1 million offshore acres at year-end 2021. In 2021, ExxonMobil relinquished 0.4 million net offshore acres.
Mozambique
ExxonMobil’s net acreage totaled 1.8 million offshore acres at year-end 2021. During the year, a total of 1.5 net development wells were completed. Development activities continued on the Coral South Floating LNG project.
Nigeria
ExxonMobil’s net acreage totaled 0.9 million offshore acres at year-end 2021.
ASIA
Azerbaijan
ExxonMobil's net acreage totaled 7 thousand offshore acres at year-end 2021. During the year, a total of 0.7 net development wells were completed.
Indonesia
ExxonMobil’s net acreage totaled 0.1 million onshore acres at year-end 2021.
Iraq
ExxonMobil’s net acreage totaled 36 thousand onshore acres at year-end 2021. Oil field rehabilitation activities continued during 2021 and across the life of this project will include drilling of new wells; working over of existing wells; and optimization, debottlenecking and expansion of facilities.
Kazakhstan
ExxonMobil’s net acreage totaled 0.3 million acres, of which 0.2 million net acres were offshore at year-end 2021. During the year, a total of 2 net development wells were completed. Development activities continued on the Tengiz Expansion project.
Malaysia
ExxonMobil’s interests in production sharing contracts covered 0.2 million net acres offshore at year-end 2021.
Qatar
Through our joint ventures with Qatar Energy, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2021. ExxonMobil participated in 62.2 million tonnes per year gross liquefied natural gas capacity and 3.4 billion cubic feet per day of flowing gas capacity at year-end. During the year, a total of 4.8 net development wells were completed. The North Field Production Sustainment Integrated Drilling and Looping project was funded in 2021. Effective January 1, 2022, ExxonMobil no longer participates in the Qatar Liquefied Gas Company Limited (QG1) venture, representing 3.6 thousand net acres and 9.9 million tonnes per year gross liquefied natural gas capacity.
Russia
ExxonMobil’s net acreage holdings in Sakhalin totaled 85 thousand offshore acres at year-end 2021. During the year, a total of 0.9 net development wells were completed.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 16 thousand acres at year-end 2021. During the year, a total of 0.2 development wells were completed.
United Arab Emirates
ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2021. During the year, a total of 0.6 net development wells were completed. Development activities continued on the Upper Zakum 1 MBD Sustainment project.
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s net acreage totaled 1.8 million acres offshore and 10 thousand acres onshore at year-end 2021.
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 tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia. The Jansz-Io Compression project was funded in 2021. Development activities continued on the Gorgon Stage 2 project during the year.
Papua New Guinea
ExxonMobil’s net acreage totaled 3.4 million acres, of which 1.2 million net acres were offshore at year-end 2021. In 2021, ExxonMobil relinquished 2.1 million net offshore acres. The Papua New Guinea (PNG) liquefied natural gas integrated development includes gas production and processing facilities in the southern PNG Highlands, onshore and offshore pipelines, and a 6.9 million tonnes per year liquefied natural gas facility near Port Moresby.
WORLDWIDE EXPLORATION
At year-end 2021, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 18.3 million net acres were held at year-end 2021.
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 28 million barrels of oil and 2,500 billion cubic feet of natural gas for the period from 2022 through 2024. 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
Year-End 2021
Year-End 2020
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net
Gross and Net Productive Wells
Consolidated Subsidiaries
United States 19,401 7,566 18,670 10,773 19,631 7,878 20,480 12,195
Canada/Other Americas 4,656 4,548 3,209 1,247 4,754 4,644 3,276 1,275
Europe 439 116 441 207 559 126 487 221
Africa 1,102 416 24 10 1,141 432 26 10
Asia 1,038 333 137 80 974 310 132 78
Australia/Oceania 522 99 94 40 540 102 90 38
Total Consolidated Subsidiaries 27,158 13,078 22,575 12,357 27,599 13,492 24,491 13,817
Equity Companies
United States 12,108 4,793 3,355 333 12,368 4,851 4,223 417
Europe 57 20 547 171 57 20 552 172
Asia 225 56 168 35 217 54 157 32
Total Equity Companies 12,390 4,869 4,070 539 12,642 4,925 4,932 621
Total gross and net productive wells 39,548 17,947 26,645 12,896 40,241 18,417 29,423 14,438
There were 23,645 gross and 20,528 net operated wells at year-end 2021 and 25,595 gross and 22,239 net operated wells at year-end 2020. The number of wells with multiple completions was 1,082 gross in 2021 and 1,067 gross in 2020.
B. Gross and Net Developed Acreage
Year-End 2021
Year-End 2020
Gross Net Gross Net
(thousands of acres)
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States 12,180 7,503 12,834 7,971
Canada/Other Americas (1)
2,905 2,075 2,944 2,071
Europe 1,980 1,078 2,231 1,189
Africa 2,409 818 2,409 818
Asia 1,929 557 1,938 561
Australia/Oceania 3,242 1,067 3,262 1,068
Total Consolidated Subsidiaries 24,645 13,098 25,618 13,678
Equity Companies
United States 687 163 928 208
Europe 3,646 1,116 3,667 1,118
Asia 701 160 701 160
Total Equity Companies 5,034 1,439 5,296 1,486
Total gross and net developed acreage 29,679 14,537 30,914 15,164
(1)Includes developed acreage in Other Americas of 490 gross and 311 net thousands of acres for 2021 and 2020.
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
Year-End 2021
Year-End 2020
Gross Net Gross Net
(thousands of acres)
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States 6,751 2,807 6,969 2,967
Canada/Other Americas (1)
36,764 18,246 37,833 18,985
Europe 14,458 5,961 14,802 6,018
Africa 23,797 15,186 35,956 24,558
Asia 766 227 888 280
Australia/Oceania 8,638 4,112 12,971 6,265
Total Consolidated Subsidiaries 91,174 46,539 109,419 59,073
Equity Companies
United States 159 64 160 64
Europe 596 139 765 214
Africa 596 149 596 149
Asia - - - -
Total Equity Companies 1,351 352 1,521 427
Total gross and net undeveloped acreage 92,525 46,891 110,940 59,500
(1)Includes undeveloped acreage in Other Americas of 26,084 gross and 12,471 net thousands of acres for 2021 and 2020.
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 an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration 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. Exploration licenses in offshore eastern Canada and the Beaufort Sea are held by work commitments of various amounts and rentals. They are valid for a term of nine years. 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. Two onshore exploration concessions were initially granted prior to the amendment and are governed under Provincial Law with expiration terms through 2024.
Brazil
The exploration and production of oil and gas are governed by concession contracts and production sharing contracts. Concession contracts provide for an exploration period of up to 8 years and a production period of 27 years. Production sharing contracts provide for an exploration period of up to 7 years and a production period of up to 28 years.
Guyana
The Petroleum (Exploration and Production) Act authorizes the government of Guyana to grant petroleum prospecting and production licenses and to enter into petroleum agreements for the exploration and production of hydrocarbons. Petroleum agreements provide for an exploration period of up to 10 years and a production period of 20 years, with a 10-year extension.
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 are normally 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.
Chad
Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is 30 years and in 2017 was extended by 20 years to 2050.
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.
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 offshore blocks, A5-B, Z5-C and Z5-D. Terms for the three blocks are governed by their respective EPCCs, with blocks Z5-C and Z5-D having an initial exploration phase that expires in 2022 and block A5-B's initial exploration phase expiring in 2023 after being granted a one-year extension. The EPCCs provide a development and production period that expires 30 years after the approval of a plan of development.
Nigeria
Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC typically holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a 10-year exploration period (an initial exploration phase that can be divided into multiple optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the 10-year exploration period, and OMLs have a 20-year production period that may be extended, subject to the partial relinquishment provision of the Petroleum Industry Act (PIA) enacted on August 16, 2021.
Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for 10 years, while in all other areas the licenses are for five years. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.
OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. Commercial terms applicable to the existing joint venture oil production are defined by the Petroleum Profits Tax Act.
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12-months written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first 10 years of their duration.
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), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. In 2012, Indonesia’s Constitutional Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but stated that all existing PSCs signed with BPMIGAS should remain in force until their expiry, and the functions and duties previously performed by BPMIGAS are to be carried out by the relevant Ministry of the Government of Indonesia until the promulgation of a new oil and gas law. By presidential decree, SKKMIGAS became the interim successor to BPMIGAS. 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 five years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.
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.
Russia
Terms for ExxonMobil’s Sakhalin acreage are fixed by the current production sharing agreement between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator.
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. In 2021, one concession was extended to 2031.
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 expected 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 five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. Extensions of petroleum retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years, provided that the total period of all extensions granted does not exceed 10 years.
Information with regard to the Downstream segment follows:
ExxonMobil’s Downstream segment manufactures, trades and sells petroleum products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers around the world.
Refining Capacity At Year-End 2021 (1)
ExxonMobil
Share KBD (2)
ExxonMobil
Interest %
United States
Joliet Illinois 254 100
Baton Rouge Louisiana 521 100
Billings Montana 60 100
Baytown Texas 561 100
Beaumont Texas 369 100
Total United States 1,765
Canada
Strathcona Alberta 196 69.6
Nanticoke Ontario 113 69.6
Sarnia Ontario 119 69.6
Total Canada 428
Europe
Antwerp Belgium 307 100
Fos-sur-Mer France 133 82.9
Gravenchon France 244 82.9
Karlsruhe Germany 78 25
Trecate Italy 132 75.2
Rotterdam Netherlands 192 100
Fawley United Kingdom 262 100
Total Europe 1,348
Asia Pacific
Fujian China 67 25
Jurong/PAC Singapore 592 100
Sriracha Thailand 167 66
Total Asia Pacific 826
Middle East
Yanbu Saudi Arabia 200 50
Total Worldwide 4,567
(1)Capacity data is based on 100 percent of rated refinery process unit stream-day capacities 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 New Zealand, and the Laffan Refinery in Qatar for which results are reported in the Upstream segment.
(2)Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in 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.
The marketing operations sell products and services throughout the world through our Exxon, Esso and Mobil brands.
Retail Sites At Year-End 2021
United States
Owned/leased -
Distributors/resellers 11,315
Total United States 11,315
Canada
Owned/leased -
Distributors/resellers 2,389
Total Canada 2,389
Europe
Owned/leased 197
Distributors/resellers 5,834
Total Europe 6,031
Asia Pacific
Owned/leased 566
Distributors/resellers 1,327
Total Asia Pacific 1,893
Latin America
Owned/leased -
Distributors/resellers 489
Total Latin America 489
Middle East/Africa
Owned/leased 223
Distributors/resellers 205
Total Middle East/Africa 428
Worldwide
Owned/leased 986
Distributors/resellers 21,559
Total Worldwide 22,545
Information with regard to the Chemical segment follows:
ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.
Chemical Complex Capacity At Year-End 2021 (1)
Ethylene Polyethylene Polypropylene Paraxylene ExxonMobil
Interest %
(millions of metric tons per year)
North America
Baton Rouge Louisiana 1.1 1.3 0.5 - 100
Baytown Texas 4.0 - 0.7 0.6 100
Beaumont Texas 0.9 1.7 - 0.3 100
Corpus Christi Texas 0.9 0.7 - - 50
Mont Belvieu Texas - 2.3 - - 100
Sarnia Ontario 0.3 0.5 - - 69.6
Total North America 7.2 6.5 1.2 0.9
Europe
Antwerp Belgium - 0.4 - - 100
Fife United Kingdom 0.4 - - - 50
Gravenchon France 0.4 0.4 0.3 - 100
Meerhout Belgium - 0.5 - - 100
Rotterdam Netherlands - - - 0.7 100
Total Europe 0.8 1.3 0.3 0.7
Middle East
Al Jubail Saudi Arabia 0.7 0.7 - - 50
Yanbu Saudi Arabia 1.0 0.7 0.2 - 50
Total Middle East 1.7 1.4 0.2 -
Asia Pacific
Fujian China 0.3 0.2 0.2 0.2 25
Singapore Singapore 1.9 1.9 0.9 1.8 100
Sriracha Thailand - - - 0.5 66
Total Asia Pacific 2.2 2.1 1.1 2.5
Total Worldwide 11.9 11.2 2.8 4.1
(1)Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capacity is ExxonMobil’s interest.
Due to rounding, numbers presented above may not add up precisely to the totals indicated.

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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.
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 23, 2022)
Darren W. Woods Chairman of the Board
Held current title since: January 1, 2017 Age: 57
Mr. Darren W. Woods became a Director and President of Exxon Mobil Corporation on January 1, 2016, and Chairman of the Board and Chief Executive Officer of Exxon Mobil Corporation on January 1, 2017, positions he continues to hold as of this filing date.
Neil A. Chapman Senior Vice President
Held current title since: January 1, 2018 Age: 59
Mr. Neil A. Chapman was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation January 1, 2015 - December 31, 2017. He became Senior Vice President of Exxon Mobil Corporation on January 1, 2018, a position he continues to hold as of this filing date.
Kathryn A. Mikells Senior Vice President and Chief Financial Officer
Held current title since: August 9, 2021 Age: 56
Ms. Kathryn A. Mikells was Chief Financial Officer and a member of the board of directors of Diageo plc November 2015 - June 2021. Prior to that time, she held Chief Financial Officer positions at Xerox, ADT, Nalco, and United Airlines, where she also served as Vice President of Investor Relations and Treasurer. She became Senior Vice President and Chief Financial Officer of Exxon Mobil Corporation on August 9, 2021, positions she continues to hold as of this filing date.
Jack P. Williams, Jr. Senior Vice President
Held current title since: June 1, 2014 Age: 58
Mr. Jack P. Williams, Jr. became Senior Vice President of Exxon Mobil Corporation on June 1, 2014, a position he continues to hold as of this filing date.
Ian S. Carr Vice President
Held current title since: September 1, 2020 Age: 58
Mr. Ian S. Carr was Vice President, Strategy and Planning, ExxonMobil Refining & Supply Company May 1, 2014 - July 31, 2017. He was Vice President, Upstream Strategy and Planning, ExxonMobil Gas & Power Marketing Company August 1, 2017 - March 31, 2019. He was Vice President, Strategy and Portfolio Management, ExxonMobil Upstream Business Development Company April 1, 2019 - September 30, 2019. He was Senior Vice President, Fuels, ExxonMobil Fuels & Lubricants Company October 1, 2019 - August 31, 2020. He became President of ExxonMobil Fuels & Lubricants Company and Vice President of Exxon Mobil Corporation on September 1, 2020, positions he continues to hold as of this filing date.
Linda D. DuCharme Vice President
President, ExxonMobil Integrated Solutions Company
Held current title since: July 1, 2020, and April 1, 2019, respectively Age: 57
Ms. Linda D. DuCharme was President of ExxonMobil Global Services Company August 1, 2016 - March 31, 2019. She became President of ExxonMobil Upstream Integrated Solutions Company April 1, 2019, and President of ExxonMobil Upstream Business Development Company and Vice President of Exxon Mobil Corporation on July 1, 2020, positions she continues to hold as of this filing date.
Len M. Fox Vice President and Controller
Held current title since: March 1, 2021
Age: 58
Mr. Len M. Fox was Vice President, Chemical Business Services and Treasurer, ExxonMobil Chemical Company June 1, 2015 - January 31, 2020. He was Assistant Treasurer of Exxon Mobil Corporation February 1, 2020 - December 31, 2020. Following a special assignment, he became Vice President and Controller of Exxon Mobil Corporation on March 1, 2021, positions he continues to hold as of this filing date.
Jon M. Gibbs President, ExxonMobil Global Projects Company
Held current title since: April 1, 2021 Age: 50
Mr. Jon M. Gibbs was Vice President, Asia Pacific and Middle East, ExxonMobil Development Company January 1, 2016 - January 14, 2019. He was Upstream Organization Design Team Lead, ExxonMobil Development Company January 15, 2019 - March 31, 2019. He was President, ExxonMobil Global Services Company April 1, 2019 - June 30, 2020. He was Senior Vice President, Global Project Delivery, ExxonMobil Global Projects Company July 1, 2020 - March 31, 2021. He became President of ExxonMobil Global Projects Company on April 1, 2021, a position he continues to hold as of this filing date.
Stephen A. Littleton Vice President - Investor Relations and Secretary
Held current title since: March 15, 2020 Age: 56
Mr. Stephen A. Littleton was Assistant Controller of Exxon Mobil Corporation June 1, 2015 - April 30, 2018. He was Vice President, Downstream Business Services and Downstream Controller May 1, 2018 - March 14, 2020. He became Vice President - Investor Relations and Secretary of Exxon Mobil Corporation on March 15, 2020, positions he continues to hold as of this filing date.
Liam M. Mallon Vice President
Held current title since: April 1, 2019 Age: 59
Mr. Liam M. Mallon was President of ExxonMobil Development Company January 1, 2017 - March 31, 2019. He became President of ExxonMobil Upstream Oil & Gas Company and Vice President of Exxon Mobil Corporation on April 1, 2019, positions he continues to hold as of this filing date.
Karen T. McKee Vice President
Held current title since: April 1, 2019 Age: 55
Ms. Karen T. McKee was Vice President, Basic Chemicals, ExxonMobil Chemical Company May 1, 2014 - July 31, 2017. She was Senior Vice President, Basic Chemicals, Integration & Growth, ExxonMobil Chemical Company August 1, 2017 - March 31, 2019. She became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2019, positions she continues to hold as of this filing date.
Craig S. Morford Vice President and General Counsel
Held current title since: November 1, 2020 Age: 63
Mr. Craig S. Morford was Chief Legal and Compliance Officer of Cardinal Heath, Inc. prior to joining Exxon Mobil Corporation in May 2019. He was Deputy General Counsel of Exxon Mobil Corporation May 1, 2019 - October 31, 2020. He became Vice President and General Counsel of Exxon Mobil Corporation on November 1, 2020, positions he continues to hold as of this filing date.
James M. Spellings, Jr. Vice President, Treasurer and General Tax Counsel
Held current title since: March 1, 2010 (Vice President and General Tax Counsel)
April 1, 2020 (Treasurer) Age: 60
Mr. James M. Spellings, Jr. became Vice President and General Tax Counsel of Exxon Mobil Corporation on March 1, 2010, and Treasurer of Exxon Mobil Corporation on April 1, 2020, positions he continues to hold as of this filing date.
Theodore J. Wojnar, Jr. Vice President - Corporate Strategic Planning
Held current title since: August 1, 2017 Age: 62
Mr. Theodore J. Wojnar, Jr. was President of ExxonMobil Research and Engineering Company April 1, 2011 - July 31, 2017. He became Vice President - Corporate Strategic Planning of Exxon Mobil Corporation on August 1, 2017, a position he continues to hold as of this filing date.
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 327,689 registered shareholders of ExxonMobil common stock at December 31, 2021. At January 31, 2022, the registered shareholders of ExxonMobil common stock numbered 325,508.
On January 26, 2022, the Corporation declared an $0.88 dividend per common share, payable March 10, 2022.
Reference is made to Item 12 in Part III of this report.
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2021
Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
October 2021
- -
November 2021
- -
December 2021
- -
Total
- - (See Note 1)
During the fourth quarter, the Corporation did not purchase any shares of its common stock for the treasury, and did not issue or sell any unregistered equity securities.
Note 1 - In January 2022, the Corporation initiated a share repurchase program of up to $10 billion over 12 to 24 months.

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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 23, 2022, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 19: Income and Other Taxes”;
•“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, 2021. 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, 2021.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2021, 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
None.

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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 2022 annual meeting of shareholders (the “2022 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 “Audit Committee” portion, “Director Independence” portion, “Board Meetings and Annual Meeting Attendance” portion, and the membership table of the portion entitled “Board Committees” 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”, and “Pay Ratio” of the registrant’s 2022 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 “Director and Executive Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 2022 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 42,039,960 (1) - 66,104,769 (2)(3)
Equity compensation plans not approved by security holders - - -
Total 42,039,960 - 66,104,769
(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 65,754,069 shares available for award under the 2003 Incentive Program and 350,700 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 2022 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 2022 Proxy Statement.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, 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.