xom-20221231


			2022

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-2256

Exxon Mobil Corporation

(Exact name of registrant as specified in its charter)


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

5959 Las Colinas Boulevard, Irving, Texas 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 940-6000

(Registrant’s telephone number, including area code)

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

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

Common Stock, without par value

XOM

New York Stock Exchange

0.142% Notes due 2024

XOM24B

New York Stock Exchange

0.524% Notes due 2028

XOM28

New York Stock Exchange

0.835% Notes due 2032

XOM32

New York Stock Exchange

1.408% Notes due 2039

XOM39A

New York Stock Exchange

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

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

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

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

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

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2022, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $85.64 on the New York Stock Exchange composite tape, was in excess of $356 billion.


Class						Outstanding as of January 31, 2023
Common stock, without par value						4,070,984,988

Documents Incorporated by Reference: Proxy Statement for the 2023 Annual Meeting of Shareholders (Part III)


	EXXON MOBIL CORPORATION
	FORM 10-K
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2022

	TABLE OF CONTENTS

PART I

Item 1.	Business	1
Item 1A.	Risk Factors	2
Item 1B.	Unresolved Staff Comments	6
Item 2.	Properties	7
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28
Information about our Executive Officers		29

PART II

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

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

PART III

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

PART IV

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

Financial Section		34
Index to Exhibits		133
Signatures		134
Exhibits 31 and 32 — Certifications

PART I

ITEM 1. BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Our principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels. 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 2022. For technology licensed to third parties, revenues totaled approximately $129 million in 2022. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise, or concession.

ExxonMobil operates in a highly complex, competitive, and changing global energy business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the Corporation's philosophy on talent development.

Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of our business across the business cycle. Our career-oriented approach to talent development results in strong retention and an average length of service of about 30 years for our career employees. Compensation, benefits, and workplace programs support the Corporation's talent management approach, and are designed to attract and retain employees for a career through compensation that is market competitive, long-term oriented, and highly differentiated by individual performance.

Over 60 percent of our global employee workforce is from outside the U.S., and over the past decade 39 percent of our global hires for management, professional and technical positions were female and 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 62 thousand, 63 thousand, and 72 thousand at years ended 2022, 2021, and 2020, 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 air, water, and waste emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2022 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.7 billion, of which $3.8 billion were included in expenses with the remainder in capital expenditures. As the Corporation progresses its emission-reduction plans, worldwide environmental expenditures are expected to increase to approximately $7.3 billion in 2023, with capital expenditures expected to account for approximately 46 percent of the total. Costs for 2024 are anticipated to increase to approximately $8.2 billion, with capital expenditures expected to account for approximately 51 percent of the total.

Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments, and risks attendant to foreign operations may be found in “Item 1A. Risk Factors” and “Item 2. Properties” in this report.

ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission (SEC). Also available on the Corporation’s website are the company’s Corporate Governance Guidelines, Code of Ethics and Business Conduct, and additional policies as well as the charters of the audit, compensation, and other committees of the Board of Directors. Information on our website is not incorporated into this report.

The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

ITEM 1A. RISK FACTORS

ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses, and the pursuit of lower-emission business opportunities. Many of these risk factors are not within the company’s control and could adversely affect our business, our financial and operating results, or our financial condition. These risk factors include:

Supply and Demand

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas, and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical, and product prices and margins in turn depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity or product. Any material decline in oil or natural gas prices could have a material adverse effect on the company’s operations, financial condition, and proved reserves, especially in the Upstream segment. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on the company’s operations, especially in the Energy Products, Chemical Products, and Specialty Products segments. Our pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels also depends on the growth and development of markets for those products and services, including implementation of supportive government policies and developments in technology to enable those products and services to be provided on a cost-effective basis at commercial scale. See "Climate Change and the Energy Transition" in this Item 1A.

Economic conditions. The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government regulation or austerity programs, trade tariffs or broader breakdowns in global trade, security or public health issues and responses, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and other events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil. Our future business results, including cash flows and financing needs, will also be affected by the rate of recovery from the COVID-19 pandemic, as well as the occurrence and severity of future outbreaks, the responsive actions taken by governments and others, and the resulting effects on regional and global markets and economies.

Other demand-related factors. Other factors that may affect the demand for oil, gas, 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. In addition to direct potential impacts on our costs and revenues, market factors such as rates of inflation may indirectly impact our results to the extent such factors reduce general rates of economic growth and therefore energy demand, as discussed under “Economic conditions”. Market factors may also result in losses from commodity derivatives and other instruments we use to hedge price exposures or for trading purposes. Additional information regarding the potential future impact of market factors on our businesses is included or incorporated by reference under Item 7A. Quantitative and Qualitative Disclosures About Market Risk in this report.

Government and Political Factors

ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations.

Access limitations. A number of countries limit access to their oil and gas resources, including by restricting leasing or permitting activities, or may place resources off-limits from development altogether. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy and climate policies. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less need for outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin.

Restrictions on doing business. ExxonMobil is subject to laws and sanctions imposed by the United States or by other jurisdictions where we do business that may prohibit ExxonMobil or its affiliates from doing business in certain countries, or 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, emissions, hydraulic fracturing, or production 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, redenominate the official currency, renounce or default on obligations, renegotiate terms unilaterally, or expropriate assets.

Legal remedies available to compensate us for expropriation or other takings may be inadequate.

We also may be adversely affected by the outcome of litigation, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur; by government enforcement proceedings alleging non-compliance with applicable laws or regulations; or by state and local government actors as well as private plaintiffs acting in parallel that attempt to use the legal system to promote public policy agendas (including seeking to reduce the production and sale of hydrocarbon products through litigation targeting the company or other industry participants), gain political notoriety, or obtain monetary awards from the company. The adoption of similar legal practices in the European Union or elsewhere would broaden this risk and has begun to be applied to some of our competitors in the European Union.

Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, cybersecurity attacks, the application of national security laws or policies that result in restricting our ability to do business in a particular jurisdiction, and other local security concerns. Such concerns may be directed specifically at our company, our industry, or as part of broader movements and may require us to incur greater costs for security or to shut down operations for a period of time.

Climate Change and the Energy Transition

Net-zero scenarios. Driven by concern over the risks of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions including emissions from the production and use of oil and gas and their products. 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 play a leading role in the energy transition, including the company’s announced ambition ultimately to achieve net zero with respect to Scope 1 and 2 emissions from operations 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, carbon-based import duties or other trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support 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 lower-emission solutions. Achieving societal ambitions to reduce greenhouse gas emissions and ultimately achieve net zero will require new technologies to reduce the cost and increase the scalability of alternative energy sources, as well as technologies such as carbon capture and storage (CCS). CCS technologies, focused initially on capturing and sequestering CO2 emissions from high-intensity industrial activities, can assist in meeting society’s objective to mitigate atmospheric greenhouse gas levels while also helping ensure the availability of the reliable and affordable energy the world requires. ExxonMobil has established a Low Carbon Solutions (LCS) business unit to advance the development and deployment of these technologies and projects, including CCS, hydrogen, and lower-emission fuels, breakthrough energy efficiency processes, advanced energy-saving materials, and other technologies. The company’s efforts include both in-house research and development as well as collaborative efforts with leading universities and with commercial partners involved in advanced lower-emission energy technologies. Our future results and ability to grow our LCS business, help nations meet their emission-reduction goals, and succeed through the energy transition will depend in part on the success of these research and collaboration efforts and on our ability to adapt and apply the strengths of our current business model to providing the energy products of the future in a cost-competitive manner.

Policy and market development. The scale of the world’s energy system means that, in addition to developments in technology as discussed above, a successful energy transition will require appropriate support from governments and private participants throughout the global economy. Our ability to develop and deploy CCS and other lower-emission energy technologies at commercial scale, and the growth and future returns of LCS and other emerging businesses in which we invest, will depend in part on the continued development of supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained could adversely impact these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without commensurate reduction in demand may have unpredictable adverse effects, including increased commodity price volatility; periods of significantly higher commodity prices and resulting inflationary pressures; and local or regional energy shortages. Such effects in turn may depress economic growth or lead to rapid or conflicting shifts in policy by different actors, with resulting adverse effects on our businesses. In addition, the existence of supportive policies in any jurisdiction is not a guarantee that those policies will continue in the future. See also the discussion of “Supply and Demand,” “Government and Political Factors,” and “Operational and Other Factors” in this Item 1A.

Operational and Other Factors

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are, at least in part, within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.

Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources online as scheduled and within budget.

Project and portfolio management. The long-term success of ExxonMobil’s Upstream and Product Solutions businesses, as well as the future success of LCS and other emerging lower-emission investments, depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping, supply-chain disruptions, and inflationary cost pressures; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project start-up or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role. In addition to the effective management of individual projects, ExxonMobil’s success, including our ability to mitigate risk and provide attractive returns to shareholders, depends on our ability to successfully manage our overall portfolio, including diversification among types and locations of our projects, products produced, and strategies to 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 effectively control 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 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; annual 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, engineered, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of uncertainties, including those associated with wave, wind, and current intensity, marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rainfall events, and earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our robust facility engineering, our rigorous disaster preparedness and response, and business continuity planning.

Insurance limitations. The ability of the Corporation to insure against many of the risks it faces as described in this Item 1A is limited by the availability and cost of coverage, which may not be economic, as well as the capacity of the applicable insurance markets, which may not be sufficient.

Competition. As noted in Item 1 above, the energy and petrochemical industries are highly competitive. We face competition not only from other private firms, but also from state-owned companies that are increasingly competing for opportunities outside of their home countries and as partners with other private firms. In some cases, these state-owned companies may pursue opportunities in furtherance of strategic objectives of their government owners, with less focus on financial returns than companies owned by private shareholders, such as ExxonMobil. Technology and expertise provided by industry service companies may also enhance the competitiveness of firms that may not have the internal resources and capabilities of ExxonMobil or reduce the need for resource-owning countries to partner with private-sector oil and gas companies in order to monetize national resources. As described in more detail above, our hydrocarbon-based energy products are also subject to growing and, in many cases, government-supported competition from alternative energy sources.

Reputation. Our reputation is an important corporate asset. Factors that could have a negative impact on our reputation include an operating incident or significant cybersecurity disruption; changes in consumer views concerning our products; a perception by investors or others that the Corporation is making insufficient progress with respect to our ambition to play a leading role in the energy transition, or that pursuit of this ambition may result in allocation of capital to investments with reduced returns; and other adverse events such as those described in this Item 1A. Negative impacts on our reputation could in turn make it more difficult for us to compete successfully for new opportunities, obtain necessary regulatory approvals, obtain financing, and attract talent, or they could reduce consumer demand for our branded products. ExxonMobil’s reputation may also be harmed by events which negatively affect the image of our industry as a whole.

Projections, estimates, and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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 2022

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. No major discovery or other favorable or adverse event has occurred since December 31, 2022 that would cause a significant change in the estimated proved reserves as of that date.


Proved Reserves	Crude Oil	Natural Gas Liquids	Bitumen	Synthetic Oil	Natural Gas	Oil-Equivalent Total All Products
	(million bbls)	(million bbls)	(million bbls)	(million bbls)	(billion cubic ft)	(million bbls)

Developed
Consolidated Subsidiaries
United States	1,174	514	—	—	9,577	3,284
Canada/Other Americas (1)	377	1	2,288	248	371	2,976
Europe	5	—	—	—	408	73
Africa	236	23	—	—	307	310
Asia	2,020	47	—	—	2,037	2,407
Australia/Oceania	38	12	—	—	3,162	577
Total Consolidated	3,850	597	2,288	248	15,862	9,627

Equity Companies
United States	119	7	—	—	127	147
Europe	2	—	—	—	326	56
Africa	5	—	—	—	663	116
Asia	235	125	—	—	5,020	1,197
Total Equity Company	361	132	—	—	6,136	1,516
Total Developed	4,211	729	2,288	248	21,998	11,143

Undeveloped
Consolidated Subsidiaries
United States	1,030	538	—	—	4,068	2,246
Canada/Other Americas (1)	568	—	132	105	337	861
Europe	—	—	—	—	5	1
Africa	35	—	—	—	5	36
Asia	774	39	—	—	1,024	983
Australia/Oceania	28	2	—	—	2,846	504
Total Consolidated	2,435	579	132	105	8,285	4,631

Equity Companies
United States	—	—	—	—	—	—
Europe	—	—	—	—	54	9
Africa	—	—	—	—	—	—
Asia	521	223	—	—	7,289	1,959
Total Equity Company	521	223	—	—	7,343	1,968
Total Undeveloped	2,956	802	132	105	15,628	6,599

Total Proved Reserves	7,167	1,531	2,420	353	37,626	17,742

(1) Other Americas includes proved developed reserves of 243 million barrels of crude oil and 191 billion cubic feet of natural gas, as well as proved undeveloped reserves of 549 million barrels of crude oil and 311 billion cubic feet of natural gas.

In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; international trade patterns and relations; and other factors described in Item 1A. Risk Factors.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates and reservoir pressures. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, and significant changes in crude oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.

B. Technologies Used in Establishing Proved Reserves Additions in 2022

Additions to ExxonMobil’s proved reserves in 2022 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 Global Reserves and Resources Manager has more than 30 years of experience in reservoir engineering and reserves assessment, has a degree in Engineering, and served on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (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 2022, approximately 6.6 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 37 percent of the 17.7 GOEB reported in proved reserves. This compares to 6.3 GOEB of proved undeveloped reserves reported at the end of 2021. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 1.0 GOEB from proved undeveloped to proved developed reserves by year end. The largest transfers were related to development activities in the United States, Mozambique, Guyana, and the United Arab Emirates. During 2022, extensions and discoveries, primarily in the United States and Guyana, resulted in the addition of approximately 1.4 GOEB of proved undeveloped reserves, along with an increase of approximately 0.7 GOEB due to purchases in Asia. Also, the Corporation reclassified approximately 0.8 GOEB of proved undeveloped reserves which no longer met the SEC definition of proved reserves, primarily in the United States and Canada.

Overall, investments of $12.1 billion were made by the Corporation during 2022 to progress the development of reported proved undeveloped reserves, including $12.0 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 71 percent of the $17.0 billion in total reported Upstream capital and exploration expenditures.

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. Proved undeveloped reserves in Australia, Kazakhstan, the United 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 Kazakhstan, the proved undeveloped reserves are related to the remainder of the Tengizchevroil joint venture development that includes a production license in the Tengiz - Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. In the United Arab Emirates, proved undeveloped reserves are associated with an approved development plan and continued drilling investment for the producing Upper Zakum field.

3. Oil and Gas Production, Production Prices and Production Costs

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area for the last three years.


(thousands of barrels daily)	2022		2021		2020
	Crude Oil	NGL	Crude Oil	NGL	Crude Oil	NGL
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States	523	211	482	195	481	154
Canada/Other Americas (1)	196	2	130	3	121	5
Europe	2	—	16	3	22	5
Africa	233	5	241	7	301	11
Asia	407	23	407	21	449	23
Australia/Oceania	27	16	28	15	29	15
Total Consolidated Subsidiaries	1,388	257	1,304	244	1,403	213

Equity Companies
United States	41	1	43	1	49	1
Europe	2	—	3	—	3	—
Africa	—	—	—	—	—	—
Asia	216	59	207	60	208	62
Total Equity Companies	259	60	253	61	260	63

Total crude oil and natural gas liquids production	1,647	317	1,557	305	1,663	276

Bitumen production
Consolidated Subsidiaries
Canada/Other Americas	327		365		342

Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas	63		62		68

Total liquids production	2,354		2,289		2,349

(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States	2,531		2,724		2,668
Canada/Other Americas (1)	148		195		277
Europe	306		377		447
Africa	64		43		9
Asia	779		807		872
Australia/Oceania	1,440		1,280		1,219
Total Consolidated Subsidiaries	5,268		5,426		5,492

Equity Companies
United States	20		22		23
Europe	361		431		342
Africa	7		—		—
Asia	2,639		2,658		2,614
Total Equity Companies	3,027		3,111		2,979
Total natural gas production available for sale	8,295		8,537		8,471

(thousands of oil-equivalent barrels daily)
Oil-equivalent production	3,737		3,712		3,761

(1) Other Americas includes crude oil production for 2022, 2021, and 2020 of 120 thousand, 48 thousand, and 29 thousand barrels daily, respectively; and natural gas production available for sale for 2022, 2021, and 2020 of 45 million, 36 million, and 45 million cubic feet daily, respectively.

B. Production Prices and Production Costs

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


(dollars per unit)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total
2022
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel	93.60	97.05	91.32	103.45	94.94	94.43	96.16
NGL, per barrel	38.54	45.22	71.43	57.83	35.77	46.91	39.37
Natural gas, per thousand cubic feet	5.37	4.40	21.17	2.57	2.60	11.47	7.48
Bitumen, per barrel	—	64.12	—	—	—	—	64.12
Synthetic oil, per barrel	—	96.08	—	—	—	—	96.08
Average production costs, per oil-equivalent barrel - total	9.40	24.63	23.77	21.68	7.31	4.97	13.09
Average production costs, per barrel - bitumen	—	29.90	—	—	—	—	29.90
Average production costs, per barrel - synthetic oil	—	51.52	—	—	—	—	51.52

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

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

2021
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel	65.03	68.56	66.20	70.21	67.28	69.00	67.14
NGL, per barrel	32.24	30.51	42.31	54.57	32.62	43.07	33.65
Natural gas, per thousand cubic feet	3.02	2.92	11.83	1.67	2.11	6.64	4.33
Bitumen, per barrel	—	44.26	—	—	—	—	44.26
Synthetic oil, per barrel	—	64.73	—	—	—	—	64.73
Average production costs, per oil-equivalent barrel - total	8.33	22.47	25.31	18.92	7.16	5.14	12.15
Average production costs, per barrel - bitumen	—	22.69	—	—	—	—	22.69
Average production costs, per barrel - synthetic oil	—	48.87	—	—	—	—	48.87

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

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


(dollars per unit)	United States	Canada/ Other Americas	Europe	Africa	Asia	Australia/ Oceania	Total
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

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


	2022	2021	2020

Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States	1	1	4
Canada/Other Americas	3	5	2
Europe	—	—	—
Africa	—	—	1
Asia	—	—	—
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	4	6	7

Equity Companies
United States	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Total Equity Companies	—	—	—
Total productive exploratory wells drilled	4	6	7

Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States	—	1	—
Canada/Other Americas	4	3	1
Europe	—	—	—
Africa	—	—	—
Asia	—	—	1
Australia/Oceania	—	—	—
Total Consolidated Subsidiaries	4	4	2

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


	2022	2021	2020

Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States	473	433	412
Canada/Other Americas	33	28	36
Europe	—	1	2
Africa	3	1	2
Asia	5	4	15
Australia/Oceania	—	—	4
Total Consolidated Subsidiaries	514	467	471

Equity Companies
United States	49	13	60
Europe	—	1	1
Africa	—	1	—
Asia	10	5	5
Total Equity Companies	59	20	66
Total productive development wells drilled	573	487	537

Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States	—	4	6
Canada/Other Americas	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Australia/Oceania	—	—	1
Total Consolidated Subsidiaries	—	4	7

Equity Companies
United States	—	—	—
Europe	—	—	—
Africa	—	—	—
Asia	—	—	—
Total Equity Companies	—	—	—
Total dry development wells drilled	—	4	7

Total number of net wells drilled	581	501	553

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 2022, the company’s share of net production of synthetic crude oil was about 63 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 2022, average net production at Kearl was about 221 thousand barrels per day.

5. Present Activities

A. Wells Drilling


Wells Drilling	Year-End 2022		Year-End 2021
	Gross	Net	Gross	Net

Consolidated Subsidiaries
United States	804	472	1,059	588
Canada/Other Americas	54	40	44	33
Europe	2	1	2	1
Africa	10	2	11	2
Asia	18	5	11	3
Australia/Oceania	1	—	—	—
Total Consolidated Subsidiaries	889	520	1,127	627

Equity Companies
United States	13	2	12	—
Europe	—	—	—	—
Africa	—	—	—	—
Asia	8	3	2	1
Total Equity Companies	21	5	14	1
Total gross and net wells drilling	910	525	1,141	628

B. Review of Principal Ongoing Activities

United States

ExxonMobil’s year-end 2022 acreage holdings totaled 9.5 million net acres, of which 0.2 million net acres were offshore. In 2022, ExxonMobil relinquished 1 million net acres, of which 0.2 million 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 519.9 net exploratory and development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2022 was 0.1 million acres. A total of 0.9 net development wells were completed during the year.

Participation in Alaska production and development continued with a total of 2.6 net development wells completed.

Canada / Other Americas

Canada

Oil and Gas Operations: ExxonMobil’s year-end 2022 acreage holdings totaled 4.3 million net acres, of which 2.5 million net acres were offshore. In 2022, ExxonMobil relinquished 2.5 million net acres, of which 1.5 million were offshore. A total of 1.3 net exploratory and development wells were completed during the year.

In Situ Bitumen Operations: ExxonMobil’s year-end 2022 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 24 net development wells at Cold Lake were completed during the year.

Argentina

ExxonMobil’s net acreage totaled 2.9 million acres at year-end 2022, of which 2.6 million net acres were offshore. During the year, a total of 5.4 net development wells were completed.

Brazil

ExxonMobil’s net acreage totaled 2.6 million offshore acres at year-end 2022. During the year, a total of 1.5 net exploratory wells were completed. Development activities continued on the Bacalhau Phase 1 project.

Guyana

ExxonMobil’s net acreage totaled 4.6 million offshore acres at year-end 2022. During the year, a total of 6 net exploratory and development wells were completed. The Liza Phase 2 Unity floating production, storage and offloading vessel commenced operations, and development activities continued on the Payara project. The Yellowtail project was funded in 2022.

Europe

Germany

ExxonMobil’s net acreage totaled 1.4 million onshore acres at year-end 2022.

Netherlands

ExxonMobil’s net interest in licenses totaled 1.4 million acres at year-end 2022, of which 0.4 million acres were offshore. During the year, a total of 0.2 net development well was completed. In 2022, the Dutch Government further reduced Groningen gas extraction and continues to evaluate the timing for cessation of production.

United Kingdom

ExxonMobil’s net interest in licenses totaled 0.1 million offshore acres at year-end 2022.

Africa

Angola

ExxonMobil’s net acreage totaled 3 million acres at year-end 2022, of which 2.9 million net acres were offshore. During the year, a total of 3.3 net exploratory and development wells were completed.

Equatorial Guinea

ExxonMobil’s net acreage totaled 0.1 million offshore acres at year-end 2022.

Mozambique

ExxonMobil’s net acreage totaled 0.7 million offshore acres at year-end 2022. In 2022, ExxonMobil relinquished 1 million net offshore acres outside of the core Area 4 development. The Coral South Floating LNG development began production in October 2022.

Nigeria

ExxonMobil’s net acreage totaled 0.9 million offshore acres at year-end 2022. During the year, a total of 0.4 net exploratory and development wells were completed.

Asia

Azerbaijan

ExxonMobil's net acreage totaled 7 thousand offshore acres at year-end 2022. During the year, a total of 1 net development wells were completed.

Indonesia

ExxonMobil’s net acreage totaled 0.1 million onshore acres at year-end 2022.

Iraq

ExxonMobil’s net acreage totaled 36 thousand onshore acres at year-end 2022. During the year, a total of 0.3 net development well was completed. Oil field rehabilitation activities continued during 2022 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 at year-end 2022, of which 0.2 million net acres were offshore. During the year, a total of 2.3 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 offshore acres at year-end 2022.

Qatar

Through our joint ventures with QatarEnergy, ExxonMobil’s net acreage totaled 80 thousand offshore acres at year-end 2022. ExxonMobil participated in 52.3 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 8.2 net development wells were completed. The North Field Production Sustainment Compression project was funded in 2022. ExxonMobil also announced participation in Qatar's North Field East project via the Qatar Liquefied Gas Company Limited (QG7) venture, representing 18.5 thousand net acres and 8 million tonnes per year gross liquefied natural gas capacity expected to begin in 2026.

Russia

Effective October 14, 2022, the Russian government unilaterally terminated the Corporation's interests in Sakhalin, transferring operations to a Russian operator.

Refer to "Note 2: Russia" of the Financial Section of this report for additional information.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 16 thousand acres at year-end 2022. During the year, a total of 0.1 net development well was completed.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2022. During the year, a total of 2.8 net development wells were completed. Development activities continued on the Upper Zakum 1 MBD Sustainment project.

Australia / Oceania

Australia

ExxonMobil’s net acreage totaled 1.2 million offshore acres and 10 thousand onshore acres at year-end 2022. In 2022, 0.6 million net offshore acres were relinquished.

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. Development activities continued on the Gorgon Stage 2 project and Jansz Io Compression project during the year.

Papua New Guinea

ExxonMobil’s net acreage totaled 2.1 million onshore acres at year-end 2022. In 2022, ExxonMobil relinquished 1.2 million net offshore acres. The Papua New Guinea (PNG) liquefied natural gas integrated development includes gas production and processing facilities in the 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 2022, 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 18.8 million net acres were held at year-end 2022 and 1.2 net exploratory wells were completed during the year in these countries.

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 36 million barrels of oil and 2.3 trillion cubic feet of natural gas for the period from 2023 through 2025. 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